康涅狄格電力 (ES) 2014 Q3 法說會逐字稿

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. Jeff Kotkin.

Mr. Kotkin, you may begin.

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 Booth, 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 US 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.

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 on 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 over to Jim.

Thanks, Jeff, and thank you, everyone, for joining us this morning.

Today, I'll cover 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 $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 milder 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 of this year, adding $0.05 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 the decline in non-tracked O&M cost, 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 lower over time and storm expense.

A modest increase in gas sales 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 a $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 reduced earnings by $0.02 per share.

While higher interest cost and a decline in income from generation operations, each had a $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 were 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 national gas side, year-to-date firm sales were up 10.5%.

Even when the impact of the cold winter is factored out, conversion activity and new construction have combined to increase firm sales by 3.6%.

Given these solid earnings 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're responsible for the connected portion of the project, which includes the construction of a new overhead 345-kV transmission line on 37 miles of existing rights-of-way 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 the remaining projects filed 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 citing, 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 and Northeast Utilities history.

On average, our customers have experienced about 175,000 fewer outages and continue to perform in the top quartile among our peers.

On the gas side, our emergency call response is also better and a performance that's in the top quartile of the industry.

So, there's no question that the quality of service to our electric and gas customers has dramatically improved since the merger.

On the regulatory front, Connecticut Light and Power's rate case will conclude next month.

A draft order is expected to be issued on December 1st, with a final order expected in mid-December.

We continue to believe our case demonstrates that we have been very successful in controlling operating cost.

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 the 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 in Yankee Gas and NSTAR Gas, which are both growing at an attractive pace to the favorable customer economics.

NSTAR Gas remains on track to file for 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 operational.

Hearings were completed in October, and we expect the 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 its 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-owned generating assets are providing a hedge against New England electricity prices, as PSNH Energy Service rate is expected to be $0.095 per kilowatt hour at the start of 2015, versus about $0.155 per kilowatt hour for other New Hampshire utilities.

At the federal level, we continue to work our way through the transmission ROE proceedings before FERC.

As you know, a final decision on the original complaint was issued on October 16th and puts the base ROE on transmission assets at 10.57%.

Overall, we appreciate the fact that FERC recognizes the inherent difficulty in siting and building high-voltage transmission projects and that they should reward 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 the June 19th decision.

That clarification request is still pending.

Also, settlement discussions on the second complaint were unsuccessful.

So, the FERC designated an administrative law judge in October, and a procedural schedule has been established.

With hearings 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 the eve of our last earnings call, July 31st.

If FERC doesn't dismiss that complaint, all parties have stated they agree that the second and third complaints should be combined for hearing.

So, there's more to come on 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, on 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 Algonquin and Maritime's pipeline systems using existing routes.

Our second project is the Northern Pass transmission project, which would provide 1200 megawatts of clean energy from Canada to our region, and go a long way toward 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 our 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.

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&A's.

I will start with exciting new initiative that we and Spectra Energy announced in September, Access Northeast.

This project is a $3 billion 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 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 Maritime's and Northeast line are uniquely situated to deliver increased quantities of natural gas to the region's newest and cleanest fossil generators, since they connect to more than 60% of the region's gas-fired units.

As we have said previously, New England faces a very difficult supply situation during the winter period.

Electric generators using natural gas do not have enough firm gas capacity, and there is no leftover gas from the gas LBCs on very cold days.

As a result, when temperatures drop well below freezing, as they did frequently last winter, up to 75% of the region's 11,000 megawatts of natural gas generation can sit idle.

When that happened last winter, the region switched on fully and 50-year-old combustion turbines, which have much higher emissions and operating costs than newer, more efficient gas generation.

Last winter, higher costs were not passed on to most retail customers, because they were able to lock in lower fixed prices before the run up in natural gas prices.

This winter, however, those costs are being passed through to customers.

In New Hampshire and Massachusetts, we have seen other utilities announce wintertime 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 wintertime challenges facing New England.

The other is just keeping the lights on, should temperature drop well below 0. As we have said previously, three non-gas fire generators that were available to the grid last winter, Vermont Yankee, Salem Harbor, and Mount Tom, which together total about 1,400 megawatts, have been or will be retired this year, further challenging electric supply resources.

Access Northeast would have a significant impact on wintertime electricity supplies.

An additional 900 million cubic feet of natural gas deliverability to the region's generators could keep 5,000 megawatts of generation online during cold winter evenings.

Since we announced the project in September, we have spoken to a number of other regional policymakers, including representatives from 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 is currently in equal partnership between Spectra Energy and NU.

Estimating 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 reliability 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 seek final FERC approval in 2016 and begin construction in 2017.

Turning from gas transmission to electric transmission, I will provide you with an update on our Northern Pass project.

In September, as many of you already know, the US Department of Energy indicated that it would complete its draft environmental impact statement in March of 2015, rather than in December 2014.

UE had previously said it would evaluate certain alternative routes for the project, a step in the process we supported.

DOE has indicated that the EIS is currently being drafted and is being circulated among the various federal agencies that need to review the project.

Assuming that the draft EIS is issued in March, we currently expect to file an application with the New Hampshire Site Evaluation Committee in May of 2015.

At that point, New Hampshire's 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 length of the review period was extended from nine to 12 months in legislation that was passed in New Hampshire earlier this year, that reconfigured the site evaluation committee and provided it with a full-time staff.

While the state process is occurring, the DOE will seek and accept comments on the draft EIS before issuing a final report.

At this time, we expect the state and federal reviews will conclude early 2016.

We remain confident that 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 sell-side forecasts on NU 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 limited wintertime gas deliveries; the retirement of older generation; rising wholesale energy and capacity prices; increasing renewable portfolio standards; and carbon reduction mandates in some New England states, requiring that more than 20% of the energy consumed in the region come 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 expressed concern 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 elections 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 turning 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 have continued to roll out 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 their replacement of identified aging infrastructure.

The new law is designed to provide the financial support necessary to accelerate the replacement of this aging infrastructure.

NSTAR worked with the DPU and other gas companies and filed on October 31st 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 over, from approximately $37 million a year now 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, aging services per year.

We would remain at an accelerated level for two decades, allowing us to eliminate that aging infrastructure in a 25-year period.

I discussed 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 talking Hopkinton LNG facility in Hopkinton, Mass.

Preliminary rate making aspects associated with that project, which could cost up to $200 million, are currently before the DPU.

Now, I'd like to turn the call back to Jeff.

Thank you, Lee.

I will return the call to Vivian just remind you how to enter questions.

(Operator Instructions)

Thank you, Vivian.

The first question this morning is from Michael Weinstein from UBS.

Good morning, Mike.

Good morning.

It's Julien here.

Hey, Julian.

How you doing?

Good, thank you.

I first wanted to go back to some your commentary around reflecting the delay in Northern Pass.

Broadly speaking, how are you speaking 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 and backfill in some respects?

I know you mentioned this earlier at the analyst day.

I just wanted to get an update there.

This is Jim, Julian.

We continue to be comfortable with our long-term guidance of 6% to 8%.

We refresh that, as I mentioned on our year-end earnings call.

So, there is shifting that goes on in the transmission budget.

You may have noticed from my comments, I suggested that we actually think we may come in a little bit ahead of our plan in terms of additional spending this year alone.

In the long run, we're certainly comfortable with the guidance.

Obviously, the cash flows, given the new date for Northern Pass, they'll shift around a little bit.

Fundamentally, the growth story is the same.

Specifically within that, I'd be curious, in light of the delay in the sale and repowering, is there any additional Boston CapEx?

I know you've mentioned that before.

What's the timing, potentially, if that happens?

Julian, this is Lee.

We're evaluating any additional capital expenditures in and around the Boston, greater Boston projects now.

We're doing the final reviews of the projects, the engineering.

And little bit too early to tell if there will be any additional investments there at this point in time.

Got you.

A 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?

What is the thought process to moving forward without something like that here?

Who are the potential counterparties that you could rely upon as side generators, I suppose?

There's two elements of the project.

One element is the LDC supply side.

Of course, to the extent that we sign up anchor shippers, LDCs, and so fourth, that would go through the standard process, where you file at the PUC.

The PUC approves that, and then you go off and file it for siting.

On the generation side, that will require a NESCOE or a NESCOE-like process, whereby we would determine the cost of that aspect of the project, and that would be covered through, essentially, the electric distribution company.

So, the 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.

As you probably know, there's been a number of states that have been -- have abdicated for this process in the region.

In fact, the majority of the states have advocated for this.

Great.

Thank you.

Next question is from Travis Miller from Morningstar.

Good morning, Travis.

Good morning.

Thank you.

Following up on Julian's question there, do these pipe projects, when you 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?

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 project's construction, the spend would be largely at the end of our five-year horizon and even beyond.

But, it certainly would be upside to what we announced at the start of this year.

Is this process far enough along, or are there other gating factors that you would start including this in your CapEx forecasts, starting, perhaps, after the fourth-quarter call in your guidance?

We'll make that decision over the next couple of months as the project's prospects become more mature.

Again, the refreshed long-term CapEx forecast will be provided at the time of our year-end call in early February.

Okay.

Great.

Thanks a lot.

Thanks, Travis.

The next question is from Dan Eggers from Credit Suisse.

Good morning, Dan.

Hey, good morning, guys.

On the partnership interest in Spectra, how have you guys discussed prospectively reducing your stakes if you brought in other partners, either because of the LDC-anchor tenament -- anchor tenant aspect of it, or just to broaden out the money exposure for each one of you guys?

Dan, this is Lee.

It's really going to -- there's a number of factors that we are looking on in.

One of them is what is the other (inaudible) bringing to this investment?

In other words, what is the LDC load that they bring?

What is, even, quite frankly, load for generators?

What is the asset mix that they bring?

For instance, one of the 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, we know where the load is on the generation side, we have to optimize the LNG projects.

And we'll be looking at other partners that bring in LNG assets to this investment, as well.

So, those are the factors that we are looking on that will determine which partners we would have as part of this joint investment in Spectra.

Have you guys discussed who would give up share, or is that the idea that you'd give up share equally on a project?

We would have an equal dilution of the ownership of the project.

Okay.

On the gas LDC appetite for more pipe capacity, given the fact they're all supplied, at least for this winter, what is the rate of incremental growth in gas demand from the LDCs that they need to cover over the next, say, three to five years?

I don't have the specific numbers on that.

If you look at the AIM project, for instance, that's about 432,000 decatherms that project has been approved.

By all of the PUC's that's sitting in front of FERC right now.

That project goes in service around November 2016, we'll say.

Then if you look beyond 2016, you're looking for somewhere in the region on the LDC side, approximately 400,000 additional decatherms, or 40% of the Bcf, by the 2018 and 2019 time frames.

Current growth rates, there's about -- between the AIM project and another kinder project, there's about 400,000 decatherms.

And then you're going to be looking by 2019 timeframe, that's going to increase by another approximately 400,000 decatherms on the LDC side.

So, the AIM project will cover that growth to 2019, and this pipe fills in the next layer of growth?

Is that the idea?

The AIM project, when it comes on in 2016, basically there'll be a little bit of slack capacity in the pipelines in 2017 and 2018.

And then you start using up that slack capacity.

So, starting in 2018, 2019, 2020 timeframe, you need, for the LDCs, you need another approximately 400,000 decatherms.

Got it.

I guess it's been awhile.

With the change in your leadership in the governor mansion in Massachusetts after the elections this week, is there anything we should watch with rate cases upcoming, both in gas and electric over the next couple of years?

We do anticipate filing a gas rate case.

We've made that decision earlier in the year.

That's likely to go in, 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 the 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 a price increase is really these 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.

But, there's no policy changes or anything stated particularly out of the new governor that would be a point of concern for you guys?

The governor has been -- governor elect for three days and has not necessarily come out with any new energy policy shifts.

But we know Charlie Baker.

We've known he's been in various roles with the administration and the state, and we're confident and comfortable that his leadership will be a good leadership for the state, including around energy issues.

Okay.

Thank you, guys.

Thanks, Dan.

Next question is from Andrew Weisel from Macquarie.

Good morning, Andrew.

Good morning, thank you.

A couple of questions similar to that last one about the elections and potential changes.

Starting with New Hampshire, with the elections that just happened, some new people in the legislature.

How, if at 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?

Do you see it as a non-event in terms of approval once you file with them next year?

As you know, Andrew, Meg Hassan was reelected, so with respect, I think, business as usual regarding the commissions in New Hampshire.

Okay.

Then, in Massachusetts, you said that you expect the RFPs from NESCOE in the coming months.

Have you -- what gives you the increased confidence?

Clearly, they were waiting for a new governor.

Is your expectation that Massachusetts was just -- regardless of who wins, they're planning to move forward?

Or do you have some reason to be more confident, given the outcome of the elections?

I think the elections tend to put a pause on a number of initiatives because of the political ramifications that have taken a strong position.

We think that the administration in Massachusetts is supportive under Deval Patrick, even though they decided to reassess their position.

I think that based on what I know about Charlie Baker, he's very bright.

He understands the issues and pressures on the economy of the state.

I think he -- expect that he would fully support a NESCOE or a NESCOE-like process to move forward sooner rather than later.

Okay.

Then, on the Spectra pipeline, sorry if I missed this.

I think you said there were two elements.

The LDC would go through the regular process, and the generation would be more of a unique thing.

Can you give a ballpark of how those two pieces make up the mix of the total project?

If you look at the approximately $3 billion, the pipelines in LNG for the generation part of the business, when we talked about 1 Bcf, so about 900,000 decatherms really is geared towards providing firm gas for 5,000 megawatts.

So, the majority of it, approximately 70% or so, would be centered around serving electrical generators to ensure that there is firm gas for this 5,000 megawatts.

Let me ask differently.

If the NESCOE, for one reason or another, didn't happen or if this project didn't win the RFP, would it make sense to go forward with it just to serve the LDC customers?

Or, is it an all or none?

The LDC customers, as you know, it's going to determine on what load that you can get signed up.

If you look at, 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 and so forth.

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 go forward.

Okay.

Great.

Lastly, I'm half teasing with this one.

It's been two-and-a-half years since the NSTAR deal closed.

Why do still break out after-tax integration charges when you the report earnings?

At what point does that become part of the business?

Well, I think the merger integration process, as we filed it 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 it went extremely successful.

But, there's 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.

The merger closed in the middle of 2012.

So, we're 2.5 years into it right now.

Sounds good.

Thank you.

Thank you, Andrew.

Our next question from Carolyn Bone from Deutsche Bank.

Carolyn?

Hey guys, good morning.

Some follow-ups on Northern Pass.

Is a settlement agreement in New Hampshire still possible regarding the project?

If so, what would be the likely timeframe?

Caroline, this is Lee.

Is reaching an agreement with government, is that possible, absolutely.

You're really talking in the first half of 2015.

Obviously, with the elections that have just passed, there will be some changes, at least on the House side.

We have obviously had a lot of communications over the course of the last four months with political leaders, as well as other important stakeholders in the business community and so forth.

So, we think in the first half of 2015, we should be at a point where we believe we would be able to conclude a consensus agreement; consensus from the standpoint that we could get government and other key stakeholders behind the project.

We will have the draft EIS, we expect, in the middle of March.

And once we have that information, we will be able to then proceed to include -- we think, a consensus deal.

So, hopefully something before again the SEC filing?

Could be around there.

That would be early.

The SEC filing, yes, absolutely.

Absolutely, we hope to have that by the SEC filing.

Okay.

Great.

Apologies, I'm not sure if you already addressed this.

With regards to 2015, how are you expecting -- this is for Jim, how are you expecting updated mortality tables and lower discount rates to impact pension expense and contributions next year?

First, 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, both the downward movement in current interest rates and the impact of the mortality tables is likely to have increased pension expense, a bit.

But, we don't think it's going to be significant.

Okay.

That's great.

And then on contributions?

Are you talking about pension contributions, Carolyn?

Yes.

Actually, we're reviewing it right now.

We'd give that guidance, probably, when we give the guidance for 2015, Carolyn.

Okay.

Great.

Thanks a lot.

Thank you, Carolyn.

Next question if from Paul Patterson from Glenrock.

Morning, Paul.

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?

This, Paul, this is an Access Northeast question?

Yes.

Well, if it was a NESCOE process, as originally designed, all six states would pay for their share of the pipeline on a peak load pro-rata 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 NESCOE.

The NESCOE folks that are the team, have not necessarily proved that process, but they've looked at it, and they think that process is a workable process.

Okay.

You said the coming months, you expect an RFP process to develop.

Is there a key milestone we should be thinking about in the near-term that we should be looking out for here?

Or is it too early to say, given the recent elections and stuff?

I think it's safe to say that with the recent elections, it's too early to say.

Obviously, Connecticut, which has been a big driver of this, Governor Malloy was reelected and his administration is completely intact.

In Massachusetts, it's a new governor, as Jimmy said, that we think will be affirmative in and around in NESCOE or a NESCOE-like process.

Then, of course, you have Maine, Governor LePage was reelected, and he has probably been the most vocal supporter of getting more gas into the region, and there's been legislation authorized where they could go out and buy essentially 200,000 decatherms of gas for electric generation.

So, we think the support is there.

All of the governors that we have talked to in the region have been supportive of getting more gas in and a process that would pay for infrastructure that would bring down winter cost of electricity.

The only thing I'd add, Paul, is I think the policymakers throughout the region realize 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's a sense of urgency, and we would hope that the momentum that we have for NESCOE would pick up shortly after the first of the year.

Okay.

Great.

Then the 0.9% decrease in sales growth, I think weather-adjusted year to date, you guys indicated that you believe that was pretty much entirely because of your efforts in energy conservation.

What do you estimate would have been the sales growth without your efforts?

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 spent nearly $0.5 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 law of the land.

That insulates us from the financial consequences.

But, we estimate that our energy efficiency programs affect the sales numbers by about 2% a year.

Okay.

Great.

Thanks so much.

Thanks, Paul.

Next question is from David Paz from Wolfe.

Good morning, David.

Good morning, how are you?

Alright.

Great, going back to Access Northeast, what agencies, which ones exactly will need to approve the addition on the electric tariff?

Dave, could you get a little closer and speak up a bit?

Sure.

Hold on.

What agencies will need to approve the addition on the electric tariff, with respect to Access Northeast?

That would be, essentially, the public utility commissions of each of the states that participates in the Access Northeast project.

We would file a FERC for siting of the project, the pipelines and LNG, and then there would be subsequently, FERC would approve whatever wholesale contracts that would come out of that.

But, it's essentially the significant approval rests with the states and their PUCs and siting through FERC.

Great.

Okay.

Thank you.

Just going to Northern Pass, what is the new profile of the CapEx over 2016, 2017 and 2018, and is the total amount still expected to be about $1.4 billion?

The total amount is still estimated to be that.

But, the cash flows actually will be part of the guidance that we give in our February call.

Okay.

Great.

On the new gas opportunities, Lee, that you were discussing, how much does that adds to the planned gas CapEx you gave out earlier this year at the analyst day?

It would be an incremental $5 million per year, each year.

As I've said, that works its way up to about $62 million by 2019, at which point we're going to be replacing about 50 miles of pipe at that point.

Then, multiply that times 20, 20 years.

If you added it all up over the whole 25-year period, it's about $1.4 billion.

Great.

Thank you so much.

Thank, David.

We have no more questions.

We want to thank you for joining us today.

We look forward to seeing many of you at EEI.

If you have anymore questions today, please give John or me a call.

Take care.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.