Nov 7, 2014
Executives
Jeffrey R. Kotkin – Vice President-Investor Relations James J.
Judge – Chief Financial Officer and Executive Vice President Leon J. Olivier – Executive Vice President and Chief Operating Officer
Analysts
Julien Dumoulin-Smith – UBS Travis Miller – Morningstar Dan Eggers – Credit Suisse Andrew Weisel – Macquarie Caroline Bone – Deutsche Bank Securities Paul Patterson – Glenrock Associates LLC David Paz – Wolfe Research
Operator
Welcome to the Northeast Utilities Earnings Call. My name is Vivian and I will be your 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.
Jeffrey Kotkin. Mr.
Kotkin, you may begin.
Jeffrey R. Kotkin
Thank you, Vivian. Good morning and thank you for joining us.
I’m Jeff Kotkin, NU’s Vice President for Investor Relations. Speaking today will be Jim Judge, our Executive Vice President and Chief Financial Officer; and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development.
Also joining us today are Phil Lembo, our Treasurer; Jay Buth, our Controller; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations. Before I turn over the call to Jim, I’d like to remind you that some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S.
Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management’s current expectations and are subject to risks and uncertainty, which may cause the actual results to differ materially from forecasts and projections.
Some of these factors are set forth in the news release issued yesterday. If you have not yet seen that news release, it is posted on our website at www.nu.com and has been filed as an exhibit to our Form 8-K.
Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2013, and on Form 10-Q for the three months ended June 30, 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.
Now, I’ll turn over the call to Jim.
James J. Judge
Thanks Jeff and thank you to everyone for joining us this morning. Today, I’ll cover our third quarter financial results, our excellent operating performance again this year, progress with our 2014 transmission capital plan, and I’ll conclude with an update on regulatory developments at both the State and the Federal level, since our last earnings call.
First, our third quarter financial results. Earnings excluding integration costs were $237.6 million, or up $0.75 per share, in the third quarter of 2014, compared with earnings of $216.5 million, or $0.69 per share, in the third quarter of 2013.
I should note that the quarter’s results are in line with Wall-Street’s expectations, despite the mild of the weather this year. Our transmission segment provided all of the $0.06 per share improvement and then some.
The $0.10 per share increase in transmission earnings this quarter resulted from a few factors. Last year, we recorded a $0.05 charge related to the New England return on equity proceeding before FERC.
There was no such charge in the third quarter this year adding a nickel per share compared with last year. The recognition of certain tax benefits and the impact of a larger transmission rate base provided the remaining $0.05 per share.
Another positive driver in the quarter was a decline in non-track O&M costs which added $0.07 to our third quarter results. The significant decline in O&M for the quarter resulted primarily from lower employee related costs including lower pension and other benefits, as well as well over time and storm expense.
A modest increase in gas fields added $0.01 to the results compared with the third quarter of last year. This was due primarily to our continued customer growth, we’ve added over 7,800 new gas heating customers in the first nine months of the year.
A significant negative factor in the quarter was $0.04 per share impact associated with various tax items primarily at the parent company that benefited us last year but were absent in the third quarter this year and resulted in a higher effective tax rate this year. Other negative factors include the impact of lower electric revenues as sales declined 4.5% driven by mild summer temperatures this year as compared to a very hot summer last year, this reduced earnings per share by $0.02, higher property taxes and depreciation expense combined also reduce earnings by $0.02 per share.
While, higher interest cost and decline in income from generation operations each had $0.01 negative impact on earnings for the quarter. All other items taken together make up the remaining $0.02.
In terms of retail sales, we continue to see very different trends for natural gas and electricity. On the electric side retail sales was down 1.2% for the year, 0.9% weather adjusted.
We believe that all the decrease was due to the success of our energy conservation initiatives. On the natural gas side, the year-to-date firm sales were up 10.5% even with the impact of the cold winter is factored out conversion activity and new construction have combined to increase firm sales by 3.6%.
Given the solid earning results we continue to be comfortable with our 2014 earnings guidance of $2.60 to $2.70 per share. Turning to the operating side of the business, I will start with transmission.
During the first nine months of this year we invested approximately $460 million in our transmission projects that includes the Interstate Reliability project a collaborative effort with National Grid that will improve reliability in Connecticut-Rhode Island and southern Massachusetts. We’ve responsible for the Connecticut portion of the project, which includes the construction of a new overhead 345-kV transmission line on 37-miles of existing rates away from Lebanon, Connecticut to the Rhode Island border.
This $218 million project which was more than 60% complete as of the end of September is expected to be energized in late 2015. We remain on target to successfully complete and perhaps exceed our 2014 transmission capital program of $664 million.
We also continue to move ahead on the Greater Hartford Central Connecticut set of projects in which we expect to invest approximately $350 million. In the first quarter of 2015, we expect to receive ISO New England’s confirmation that the projects identified through the GHCC study will not have a material adverse impact on the transmission system.
The first set of projects will be submitted for Connecticut Siting Council approval in the first quarter of 2015 with a remaining projects file thereafter. Let me remind you that the GHCC consists of several small projects needed to address reliability concerns throughout Central Connecticut.
These projects are expected to be in various stages of sighting construction and in service during 2015 through 2018. Turning to our electric and gas distribution businesses, our electric service reliability metric is tracking 10% ahead of last year, which was the best year ever in North East utilities history.
On average our customers have experienced above 175,000 fuel outages and continuing to perform in the tough quartile among our peers. On the gas side, our emergency call responses also better and a performance sit in the top quartile of the industry.
So there is no question that the quality of service to our electric and gas customers has dramatically improved since the merger. On the regulatory filing Connecticut Light and Power was rate cased will conclude next month.
Addressed order is expected to be issued on December 1st, with a final order expected in mid December. We could continue to believe our case demonstrates that we have been very successful in controlling operating costs.
In fact, O&M and the cost of service is $36 million less than three years ago in spite of wage increases and in spite of inflation. The rate we request is totally driven by our strategy of targeted capital investment to improve and modernize the state’s distribution system.
More than $700 million of capital improvements have been invested since the last rate plan. The new rates are necessary to recover this investment level.
Turning to gas operations, on Monday we will welcome a new President of our gas segment. William Akley has more than 20 years of experience in all facets of the natural gas sector.
In his prior experience he had oversight of operations, pipeline safety and compliance throughout National Grid service territories in New York, Rhode Island and Massachusetts. Bill is a well-known leader in the industry with a great track record for exceptional, operational and safety performance.
We look forward to his leadership with Yankee Gas and NSTAR Gas, which are both growing in an attractive pace to the favorable customer economics. NSTAR Gas remains on track to file up new distribution rates with the Massachusetts Department of Public Utilities next month.
It will be the company’s first rate request in many years, and we expect the new rates to become effective January 1, 2016. In a moment, Lee will discuss a separate legislatively driven initiative that will have all Massachusetts gas distribution companies, including NSTAR Gas replace their older leak-prone pipes over the next 25 years.
Now I’ll move on to New Hampshire, where the Public Utility Commission has indicated that before it begins the divestiture review, it expects to complete its prudence review of our $422 million scrubber investment at Merrimack Station. That scrubber has been operating extremely well during the three years that it’s been in operation.
Hearings were completed in October, and we expect a decision in December. This past summer, Governor Hassan signed legislation ordering the state commission to undertake a study to determine whether divestiture of PSNH’s nearly 1,200 megawatts of generation would be in customers’ economic interest.
The New Hampshire PUC is required to commence the review before January 1, 2015. We believe that this review will likely be completed late next year.
If divestiture is ordered, we expect that full cost recovery of any stranded cost is likely. Currently, public service of New Hampshire generating assets are providing a hedge against New England electricity prices as PSNH’s Energy Service Rate is expected to be $0.095 per kilowatt hour at the start of 2015, versus about $0.155 per kilowatt hour of the New Hampshire utilities.
At the federal level, we continue to work our way through the transmission ROE proceedings before FERC. As you know, final decision on the original complaint was issued on October 16, and puts the base ROE on transmission assets at 10.57%.
Overall, we appreciate the fact that FERC recognizes the inherent difficulty in sighting and building high voltage transmission projects and that there should be more companies that step up and take on this risk and challenge of the work. However, we and other transmission owners have asked FERC for clarification of several elements of June 19 decision.
That clarification request is still pending. Also, several discussions on second complaint were unsuccessful.
So the FERC designated an administrative law judge in October and a procedural schedule has been established. With hearing scheduled for June 2015, the judge is expected to render an initial decision on or before October 26, 2015.
As you know, a third complaint was filed on eve of our last earnings call, July 31, and if FERC doesn’t dismiss that complaint all parties have stated they agree that the second and third complaint should be combined for hearing. So there’s more to come in these important proceedings, but we feel we have adequately reserved for any exposure to refunds.
Before concluding my formal remarks, I should mention that we continue to monitor the RFP process to be conducted by the New England States Committee on Electricity or NESCOE. The New England States can provide a great opportunity to develop projects to meet the region’s renewable energy and carbon reduction mandates, as well as address challenges in providing New England with adequate electric power resources.
The process has been slowed a bit because Massachusetts decided to take a closer look at the issue. With the elections now behind us, we expect a more definitive course of action will begin to take shape.
We expect that NESCOE will issue RFPs for both electric and natural gas transmission in the coming months. We believe we have the two best proposals to meet NESCOE’s expectation and ultimately resolve the energy supply situation in the region.
In September, we jointly announced with Spectra Energy the Access Northeast natural gas pipeline expansion project that will enhance our Algonquin and Maritimes pipeline systems using existing moves. Our second project is the Northern Pass transmission project, which will provide 1,200 megawatts of clean energy from Canada to our region and go a long way towards solving the energy supply issues here in New England.
We will cover each of these significant projects in a moment. I look forward to seeing many of you at the EEI Conference next week.
I will remind you that we plan to roll out a five-year capital spending forecast and provide 2015 EPS guidance, as well as long-term prospects on the fourth quarter earnings call scheduled for early February. Now I’ll turn the call over to Lee.
Leon J. Olivier
Thank you, Jim. I will provide you with an update on our major capital initiatives, and then turn the call back over to Jeff for Q&As.
I will start with the exciting new initiatives that we in Spectra Energy announced in September, Access Northeast. This project is $3 million enhancement of Spectra’s existing natural gas transmission systems in New England deliver at least an additional 1 billion cubic feet per day of natural gas into New England.
Like the other natural gas transmission projects that have been announced in recent years in New England. This project is geared to serve both the LDC and the natural gas generation needs of the region.
Spectra Energy’s pipelines in New England, the Algonquin and Maritimes and Northeast lines are uniquely situated to deliver increase quantities of natural gas to the regions newest and cleanest process of generators since they connect to more than 60% of the regions gas fired units. As we’ve said previously, the New England faces a very difficult supply situation during the winter period.
Electric generators using natural gas did not having a firm gas capacity and there is no left over gas from the gas LDCs on very cold days. As a result, the temperatures drop well below freezing as they did frequently last winter up to 75% of the regions 11,000 megawatts of natural gas generation can sit idle.
When that happened last winter, the regions switched on fully and (indiscernible) year-old combustion turbines which have much higher emissions in operating cost than newer more efficient gas generation. Last winter, higher cost would not passed on to most retail customers, because they were able to lock in lower fixed prices before the runoff in natural gas prices.
This winter however, those costs are being passed through to customers. In New Hampshire and Massachusetts, we’ve seen other utilities announce winter time energy rates of $0.15 to $0.16 per kilowatt-hour compared with $0.08 to $0.09 per kilowatt-hour last winter.
And the economic impact is only one of the winter time challenges facing New England the other was just keeping the lights on so temperature drop well below zero. As we’ve said previously, three non-gas fire generators that were available to the grid last winter, Vermont Yankee, Salem Harbor and Mt.
Tom, which together total about 1,400 megawatts, have been or will be retired this year, for the challenging electric supply resources. The Northeast would have a significant impact on winter time of electricity supplies.
In additional 900 million cubic feet of natural gas deliver to the region generators could keep 5,000 megawatts of generation online during cold winter reasons. Since we announced the project in September, we have spoken to a number of other regional policy makers including representatives come to New England States Committee on Electricity, or NESCOE as well as other companies that may have an interest in co-investing in the project.
To remind you, Access Northeast was currently in equal partnership between Spectra Energy and NU, estimated the cost about $3 billion and expected to come online in November of 2018. Over the balance of 2014, we expect to work with other parties to establish the levels of firm natural gas supply required to ensure both generation and the liability and the LDC demand growth is met.
This will position us to firm up contracts with local gas distribution companies and begin seeking regulatory approvals in 2015. We continue to expect to see final FERC approval in 2016 and begin the construction in 2017.
Turning from gas transmission to electric transmission, I’ll provide you with an update on our Northern Pass project. In September, as many of you already know the U.S.
Department of Energy indicated that would complete its draft Environmental Impact Statement in March of 2015 rather than in December 2014. DOE had previously said it would evaluate certain alternative routes of the project is stepping the process we supported, DOE has indicated that, yes, it’s currently being drafted and is being circulated among the various federal agencies that need to review the projects.
Assuming that the draft EIS is issued in March, we currently expect to file an application with New Hampshire Site Evaluation Committee in May of 2015. At that point, New Hampshire siting regulators will have up to 60 days to determine that the application is complete and then 12 months to act on it.
The maximum rent of review period was extended from 9 to 12 months in legislation that was past in New Hampshire earlier this year, that refigured the Site Evaluation Committee and provided it with a fulltime staff. Although, state process is occurring the deal we will seek and accept comments on the draft EIS before issuing a final report.
At this time, we expect to state the federal reviews will conclude around the 2016. We remain confidence at the project will bring significant economic and environmental value to New Hampshire and New England and will proceed.
Based on a two-year construction period we believe Northern Pass will enter service in the second half of 2018. I assume that many of the self side forecast and then you already account for this construction schedule.
The need for Northern Pass has never been more evident as New England works to address the challenges of a limited winter time gas deliveries, the retirement of older generation, rising wholesale energy and capacity prices, increasingly movable portfolio standards, and carbon reduction mandates in some New England States requiring that more than 20% of the energy consumed in the region comes from renewable sources by 2020. In recognition of the region’s growing energy challenge, the New Hampshire business and industry association has recently called on the New Hampshire and New England policymakers to allow for the development of energy infrastructure projects, while working through local concerns.
The BIA is a statewide organization that represents over 400 companies has express concerned over the potential negative impact on the economy, if prompt action is not taken. The energy situation was also an issue in this year’s election in New Hampshire.
Several candidates have recognized the urgency of the situation and called for a balanced approach to develop needed solutions. We look forward to working towards these solutions.
Before I turn on the call back to Jeff for Q&A, I will comment on an additional area where we expect to show significant growth and investment opportunities. This is our natural gas distribution business.
We continue to rollout our Yankee Gas initiatives under the new enabling legislation signed by Governor Malloy last year. As Jim mentioned, in Massachusetts, the legislature enacted an important piece of legislation earlier this year, requiring the Massachusetts gas companies to ramp up the replacement of identified ageing infrastructure.
The new law is designed to provide the financial support necessary to accelerate replacement of this ageing infrastructure. NSTAR work with the DPU and other gas companies had filed on October 31, a gas system enhancement program or GSEP.
The GSEP includes our accelerated replacement plan and a new tariff that provides the company an opportunity to collect the cost of these new programs on an annual basis through a newly designed and reconciling tracking mechanism. The tracker would recover each projected year’s revenue requirements.
NSTAR Gas’s investments in pipe replacement would grow by at least $5 million per year from approximately $37 million a year now and to about $42 million a year in 2015 to about $47 million in 2016. And eventually to about $62 million by 2019 by which time we will be replacing 50 miles of older gas main and thousands of individual ageing services per year.
It would remain at an accelerated level for two decades allowing us to eliminate that ageing infrastructure in a 25 year period. I discuss a settlement of our increased investment in Massachusetts natural gas facilities in our August call.
Another element of this year’s legislation is expansion of the natural gas delivery system to new customers. We expect to file our expansion plan promptly after the DPU issues its regulations in this matter.
The third element is a significant upgrade of our 3 billion cubic feet Hopkinton LNG facility and Hopkinton, Mass. Preliminary rate makes an aspects associated with that projects, which could cost up to $200 million are currently before the DPU.
Now I would like to turn the call back to Jeff.
Jeffrey R. Kotkin
Thank you, Lee. And I’ll turn the call to Vivian and just to remind you how to enter questions.
Operator
Thank you. We will now begin the question-and-answer session.
(Operator Instructions)
Jeffrey R. Kotkin
Thank you, Vivian. First question this morning is from Michael Weinstein from UBS.
Good morning, Mike.
Julien Dumoulin-Smith – UBS
Hi, good morning. It’s Julien here.
Jeffrey R. Kotkin
Hey, Julien how you doing?
Julien Dumoulin-Smith – UBS
Good. Thank you.
I’d first wanted to go back to some of your commentary around reflecting the delaying Northern Pass. Just broadly speaking, how you feeling about EPS growth rate targets in light of the delay and specifically what kind of latitude do you have today to shift around CapEx to address the delay in backfield in some respects.
I know you’ve mentioned this earlier at the Analyst Day, just wondering to get an update there?
James J. Judge
Yes, this is Jim, Julien. We continue to sort of be comfortable with our long-term guidance of 6% to 8%.
We refresh that as I mentioned on our year-end earning call. So the reshipping that was on transmission budget, you may have noticed from my comments, I suggested that we actually think we made comment a little bit ahead of our plan in terms of additional spending this year alone.
So in the long run it was certainly comfortable with the guidance, obviously the cash flows given the new date for Northern Pass though shipped around a little bit, but fundamentally the real story is the same.
Julien Dumoulin-Smith – UBS
And specifically within that I’d be curious in light of the delay in sale and repowering. Is there any additional Boston CapEx, I know you’ve mentioned that before and what’s the timing potential if that happens?
Leon J. Olivier
Julien, this is Lee. We’re evaluating the any additional capital expenditures in and around the Boston, Greater Boston projects now.
We’re doing kind of the final reviews of the projects, the engineering and little bit too early to tell that there will be any additional investments there at this point in time.
Julien Dumoulin-Smith – UBS
Got you. And just the second question if you don’t mind.
On your partnership with Spectra here, does that pipeline necessitate NESCOE or a comparable procurement – state procurement effort, or what is the thought process to moving forward without something like that here? Who are the potential counterparties that you could rely upon a side generator I suppose?
Leon J. Olivier
Yes, I mean there are two elements of the project. One element is the LDC supply side and of course to the extent that we sign out anchor shippers, LDCs and so forth, that would go through the standing process where you file up the PUC, the PUC approves that then you go up and file it for presiding.
On the generation side that will require a NESCOE or a NESCOE like process whereby we would determine the cost of that aspects of the project and that would be covered through essentially the electric distribution companies of EDCs because it’s really an EDC issue and that is likely to be put together and filed, the project announced and filed at the respective states that want to support the project to bring down overall electric prices in the region and ensure that there is a sufficient supply to ensure reliability in the region. And as you probably know there has been a number of states that had been – had abdicated to this process in the region, in fact the majority of the states have abdicated for this.
Julien Dumoulin-Smith – UBS
Great, thank you.
Jeffrey R. Kotkin
All right, thanks Julien. Next question is from Travis Miller from Morningstar.
Good morning Travis.
Travis Miller – Morningstar
Good morning. Thank you.
I was just kind of following-up on Julien’s question there, do these pipe projects – throw those into the mix in the next two three years. Does that have upside potential to your medium-term, long-term earnings growth forecast?
James J. Judge
Certainly, the 6% to 8% guidance that we provided this time of this year did not anticipate or include the partnership with Spectra. Again, the projects construction, the spend would be largely at the end of our kind of five year horizon and even beyond.
But it certainly would be upside to what we announced at the side of this year.
Travis Miller – Morningstar
And is this process far enough along or are there other gating factors that you would start including this in your CapEx forecasts, starting perhaps even after the fourth quarter call in your guidance.
James J. Judge
Yes, we’ll make that decision over the next couple of months is the projects prospects become more than sure, again the refresh long-term CapEx forecast will be provided at the time of our year-end call in early February.
Travis Miller – Morningstar
Okay, great. Thanks a lot.
Operator
Thanks, Travis. Next question is from Dan Eggers from Credit Suisse.
Good morning, Dan.
Dan Eggers – Credit Suisse
Hey, good morning, guys. Just on the partnership interest with Spectra, how have you guys discussed prospectively reducing your stakes if you ride another partners because of the kind of the LDC anchor tenants aspect of it or just to broaden out the money exposure for each one of you guys.
Leon J. Olivier
Dan, this is Lee Olivier. Its really going to – there is a number of factors that we are looking in – one of them is what is the counterparty bring to this investment in another words what is the LDC low that they bring whether is even quite frankly low to generators, what is the asset mix that they bring because for instance one of things that.
This project is a combination of pipeline and LNG. So we are going to be looking at the regional LNG assets and once we better understand on the LDC side where the load is, kind of know where the load is on the generation side, we have to optimize the LNG projects and we’ll be looking that other projects that bring in LNG assets to this investment as well.
So those are kind of the factors that we are looking on that will determine which partners, we would have as part of this investment with Spectra.
Dan Eggers – Credit Suisse
Have you guys discussed who would give up share or is it ideally you give up share equally on a project.
Leon J. Olivier
Dan, we would have an equal dilution of the ownership of the project.
Dan Eggers – Credit Suisse
Okay. And then on the gas LDC advertise for more pipe capacity.
You given the fact they are all supplied at least for this winter. What is the rate of incremental growth in gas demand from the LDC that they need to cover over the next say three to five years?
Leon J. Olivier
Yes. I don’t have the specific numbers on that.
But if you look out the AIM project for instance that’s about 432,000 deco therms that project has been approved by all of the PUC that sitting in front of FERC right now. And that project goes to service around November of 2016 will say, and then if you look beyond 2016 you are looking for somewhere in the region on the LDC side approximately 400,000 additional deco therms or 40% of the Bcf by the 18 and 19 timeframe.
So, common growth rates where there is about between the AIM projects and another Kinder project there is about 400,000 deco therms, and even if you looking by 2019 time frame that’s going to increase by another approximate 400,000 deco therms on the LDC side.
Dan Eggers – Credit Suisse
So the AIM project will cover that growth to 2019, and this pipe kind of fills in next layer of growth. Is that the idea?
Leon J. Olivier
Yes, the AIM project going to come on in 2016 basically there will be a little bit slight capacity in the pipelines in 2017 and 2018, and then you start using up that slight capacity. So 2019, starting in the 2018, 2019, 2020 time frame for the LDCs you need another approximately 400,000 deco therms.
Dan Eggers – Credit Suisse
Okay, got it. And I guess this has been a while, but with the change in your leadership and the Governor mansion in Massachusetts after the election this week.
Is there anything we should watch with kind of rate cases upcoming both the gas and electric over the next couple of years?
Leon J. Olivier
Yes, we do anticipate filing a gas rate case. We made that decision early in the year, that’s we were going in December, it’s not really impacted by the election, because we continue to have that as our base plan.
And we feel confident that the story is going to be similar to one that we have in Connecticut Light and Power that we’ve been doing a great job, controlling costs while services dramatically improved and the driver for the need for price increase is really the investments that we’re making in our infrastructure to provide that improved service. So we’re optimistic that we’ll have a favorable outcome in that rate case.
Dan Eggers – Credit Suisse
But there is no policy changes or anything stated particularly out of the new governor that would be a point of concern for you guys?
Leon J. Olivier
Governor elect for three days and has not necessarily come out with an new energy policy shifts, but we know Charlie Baker would known he has been in various roles with the administration in the state and we’re confident and comfortable that his leadership will be a good leadership for the state including around energy issues.
Dan Eggers – Credit Suisse
Okay, thank you guys.
Jeffrey R. Kotkin
Thanks, Dan. Next question is from Andrew Weisel from Macquarie.
Good morning, Andrew.
Andrew Weisel – Macquarie
Good morning, thank you. A couple of questions similar that last one is about the change in the elections and potential changes.
So starting I guess with New Hampshire with the elections that just happens some people in the legislature, how is that all, would that affect the SEC either the site evaluation committee that is. Would there be any potential changes, any potential shift in priorities or anything like that or do you see it as a non-event in terms of approval once you file with them next year?
Jeffrey R. Kotkin
Yes, I think as you know Andrew, may be Hassan was reelected so we’ve expect that the business as usual regarding the commissions in New England.
Andrew Weisel – Macquarie
Okay, then in Massachusetts that, you said that you expect the RFPs from NESCOE in the coming months, have you – what gives you the increase confidents, I mean, clearly they were waiting for a new Governor, is your expectation that Massachusetts was just regardless of who wins, they are planning to move forward, or do you have some reason to be more confident given the outcome of the elections?
James J. Judge
I think, the election tend to put a pause on the number of initiatives, because of the political ramifications are taking a strong position. We think that the administration in Massachusetts is support of under Deval Patrick even though they decided to reassess their positions, I think that based on what I know about Charlie Baker is very bright, we understand.
So to the issues and pressures on the economy of the state and I think he expect that he would fully support NESCOE. And NESCOE like process to move forward sooner rather than later.
Andrew Weisel – Macquarie
Okay, then on the Spectra pipeline, sorry if I miss that, I think you said there were sort of two elements of the LDC would go to the regular process and the generation would be more of a unique then, can you give just a ball park of how those two pieces make up the mix of the total project?
James J. Judge
If you look at approximately $3 billion, the pipelines in LNG for the generation part of the business and we’ve talked about 1 Bcf, so about 900,000 dekatherms really is geared towards providing firm gas for 5,000 megawatts. So the majority of it approximately 70%, so would be centered in around the serving electrical generators to ensure that there is firm gas for this 5,000 megawatts.
Andrew Weisel – Macquarie
Let me ask differently, if the NESCOE for one reason or another didn’t happen or this project didn’t win the RFP, would it make sense to go forward. It just to serve the LDC customers or is that and all or none?
James J. Judge
The LDC customers, as you know it’s going to determine on what low you can get signed up and if you look on for instance the 400,000 that I talked about, not all of that 400,000 would be able to be touched by the Spectra project. So, there would still be enough in our estimation for the LDC, we believe, based upon where the load is and where our pipeline would run, that there would be enough to make that portion of the project going forward.
Andrew Weisel – Macquarie
Okay, great. Then lastly, I’m kind of half teasing with this one.
But it’s been 2.5 years since the NSTAR deal closed. Why do you still breakout after tax integration charges when you report the earnings at what point to that has become part of the business.
Leon J. Olivier
Well, I think the merger integration process as we filed with the regulators is a three to four-year ramp up. We are just now experiencing the benefits of systems integration.
This quarter we completed our new financial system integration and I’m proud to say we’re extremely successful, but this more integration to come, facilities consolidation is ongoing. So merger savings don’t happen overnight, and I think we’ve been deliberate and successful in achieving them, but it’s essentially a three-year period.
And the merger closed in the middle of 2012. So we are 2.5 years into it right now.
Andrew Weisel – Macquarie
Sounds good. Thank you.
Jeffrey R. Kotkin
?
Caroline Bone – Deutsche Bank Securities
Hey guys, good morning.
Jeffrey R. Kotkin
Good morning.
Caroline Bone – Deutsche Bank Securities
Just I guess some follow-ups on Northern Pass. Is a settlement agreement in New Hampshire is still possible regarding the project and if so what would be likely timeframe.
Leon J. Olivier
Caroline, this is Lee. Its reaching an agreement with government is that possible absolutely.
That you are little talking in the first half of 2015, obviously with the elections that have just past that there will be some changes at least from the house side and we have obviously had a lot of communications over the course of the last four months with for growth leaders as well as other important stakeholders in the business community and so forth. And so we think in the first half of 2015 should be at a point where we believe what we would be able to conclude a consensus agreement, consensus from the standpoint that we could get the government another key stakeholders behind the project will have the draft EIS.
We expect in the middle of March. And once we have that information we will be able to then proceeding include we think a consensus deal.
Caroline Bone – Deutsche Bank Securities
So, hopefully something before again the SEC filing.
Leon J. Olivier
It could be around there that would be early hope the SEC filing. Yes, absolutely, absolutely.
Caroline Bone – Deutsche Bank Securities
Okay.
Leon J. Olivier
Absolutely we hope that by the SEC filing.
Caroline Bone – Deutsche Bank Securities
Okay, great.
Leon J. Olivier
Yes.
Caroline Bone – Deutsche Bank Securities
And then I apologize, I am not sure if you already address this, but with regards to 2015, how are you expecting – and this is for Jim, how are you expecting updated mortality tables and lower discount rates to impact pension expense and contributions next year?
James J. Judge
First, I guess let me remind you that we have specific cost recovery mechanisms in several jurisdictions and about 30% of pension costs have an earnings impact. With that said mostly the downward movement in current interest rates and the impact of the mortality tables is likely to have an increased pension expense a bit, but we don’t think it’s going to be significant.
Caroline Bone – Deutsche Bank Securities
Okay, that’s great. And then on contributions?
James J. Judge
Are you talking about pension contributions, Caroline?
Caroline Bone – Deutsche Bank Securities
Yes, yes.
James J. Judge
Actually, we’re viewing it right now and we will give that guidance probably when we give the guidance for 2015 Caroline.
Caroline Bone – Deutsche Bank Securities
Okay, great. Thanks a lot.
Jeffrey R. Kotkin
All right, thanks Caroline. Next question is from Paul Patterson from Glenrock.
Good morning, Paul.
Paul Patterson – Glenrock Associates LLC
Good morning. Just to circle back on the NESCOE RFP process and the generation component.
How will these guys allocate the recovery of the generation revenue requirement component of the pipeline?
Leon J. Olivier
This Paul was – this is an Access Northeast question.
Paul Patterson – Glenrock Associates LLC
Yes.
Leon J. Olivier
Yes, it was a NESCOE process as originally designed. All six states would pay for their share of the pipeline on a peak load prorate share basis.
If it’s obviously fewer states than six then they would again pay for their load share piece of the project. So that’s how we envision it in the NESCOE.
The NESCOE folks that are the team that have not necessarily proved that process, but they’ve looked out at it and they think that process is a workable process.
Paul Patterson – Glenrock Associates LLC
Okay. And then you said in the coming months, you expect sort of an RFP process to develop.
Is there a key milestone we should be thinking about in the near-term that that we should be looking out for here or is it just too early to say given the reasonable elections and stuff?
Leon J. Olivier
I think it’s safe to say that with the recent elections is too early to say. Obviously, the Connecticut, which has been a big driver of this, Governor Malloy was reelected and his administration has been completely intact.
In Massachusetts, it’s a new Governor as Jimmy said that we think will be affirmative around a NESCOE or NESCOE like process and then of course you had Maine Governor LePage was reelected and he’s probably been the most vocal supporter of getting more gas into the region and there has been legislation authorized where they could go out and buy essentially 200,000 dekatherms of gas for electric generation. So we think the supporters there – all of the governance that we talk to in the region had been supportive of getting more gas and in a process that would pay for infrastructure that would bring down winter cost of electricity.
Paul Patterson – Glenrock Associates LLC
Okay.
Leon J. Olivier
The only thing I would add Paul is that I think the policymakers throughout the region realized that this is not a one-year problem that to come up with a solution, given the construction lead time. The more you delay, the more likelihood is that you’re going to have these types of prices for yet another winter out in the future.
So I do think there is a sense of urgency and we would hope that the momentum in NESCOE would pick up shortly after the first of the year.
Paul Patterson – Glenrock Associates LLC
Okay, great. And then the 0.9% decrease in sales growth I think weather adjusted year-to-date.
You guys indicated that you believe that was pretty entirely because of your efforts in energy conversation. What do you estimate would have been the sales growth without your efforts?
Leon J. Olivier
Now, sales – weather adjusted were down 0.9%. We think that the spend that we have – dampened sales growth, the energy efficiency spend by approximately 2%.
We spend nearly $0.05 billion a year system-wide now in energy efficiency and it does have a real impact. As you know, Connecticut and Massachusetts which are the two major states that we serve in terms of load and sales, now has decoupling as the lower the land.
So that insulates us from the financial consequences, but we estimate that on an energy efficiency programs affect the sales numbers by about 2% a year.
Paul Patterson – Glenrock Associates LLC
Okay, great. Thanks so much.
Jeffrey R. Kotkin
Thank you, Paul. Next question is from David Paz from Wolfe.
Good morning David.
David Paz – Wolfe Research
Good morning. How are you?
Jeffrey R. Kotkin
All right.
David Paz – Wolfe Research
Great. Just going back to Northeast, what agencies – which ones exactly will need to approve the addition on the electric tariff?
Leon J. Olivier
David, could you get a little closer and speak up a bit.
David Paz – Wolfe Research
Sure, hold on. What agencies will need to approve addition on the electric tariff with respect to Access Northeast?
Leon J. Olivier
That would be essentially the public utility commissions of each of the states that participate in the Access Northeast project. And we would – we would file a FERC for citing of the project for the pipelines and LNG.
And then, we’d be subsequently FERC would approve, whatever wholesale contracts that would come out of them. But it’s essentially the significant approval rest with the stakes in their PUCs and citing through FERC.
David Paz – Wolfe Research
Great. Okay, thank you.
And then just going to Northern Pass, what is the new profile of the CapEx over 2016, 2017, and 2018 and as the total amount still expected to be about $1.4 billion?
James J. Judge
Total amount is still estimated to be that, but the cash flow is actually will be part of the guidance that we give in our February call.
David Paz – Wolfe Research
Okay, great. And then just on the gas – the new gas opportunities.
Lee that you’re discussing, how much does that add to the plan to gas CapEx you gave out earlier this year at the Analyst Day.
Leon J. Olivier
It would be an incremental $5 million per year – each year and as I’ve set that works it’s way up to about $62 million by 2019, and at which point, we’re going to be replacing about 50 miles supply at that point. And then multiply that time is 20 years, and if you added it all up over the whole 25 years, it’s about $1.4 billion.
David Paz – Wolfe Research
Great, great. Thank you so much.
Leon J. Olivier
Thank you.
James J. Judge
All right.
Jeffrey R. Kotkin
Thanks, David. We have no more questions.
So we want to thank you for joining us today. Look forward to seeing many of you at EEI.
And if you have any more questions today please give John or me a call. Take care.
Operator
Thank you, ladies and gentlemen. This concludes today’s conference.
Thank you for participating. You may now disconnect.