康涅狄格電力 (ES) 2015 Q3 法說會逐字稿

Good morning, and welcome to the Eversource Energy third-quarter earnings call. My name is Brandon and I'll be your operator for today.

(Operator Instructions)

Please note this conference is being recorded and I will now turn it over to Jeff Kotkin. You may begin, sir.

Thank you, Brandon. 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 US Private Securities Litigation Reform Act of 1995. These forward 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 forecast and projections.

Some of these factors are set forth in the news release issued yesterday. Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2014, and our quarterly report on Form 10-Q for the three months ended June 30, 2015. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night on our website under presentations and webcasts, and in our most recent 10-K and 10-Q.

Speaking today will be Jim Judge, Executive Vice President and CFO, and Lee Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development. Also joining us today are Werner Schweiger, our Executive Vice President and Chief Operating Officer; Phil Lembo, our Vice President and Treasurer; Jay Booth, our Vice President and Controller; and John Marrero, our 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 third quarter financial results, which were in line with our guidance range for the full year, an update on several legislative and regulatory items, and I'll close with an update on certain transmission projects.

Let me start with slide 4 and our financial results. Excluding integration costs, we earned $237.6 million, or $0.75 per share, in the third quarter of 2015, identical to our earnings in the third quarter of 2014, and in line with Wall Street's expectations. Over the first nine months of 2015, we earned $704.5 million, or $2.21 per share, excluding integration costs, compared with earnings of $611.3 million, or $1.93 per share, in the first nine months of 2014. As a result of our strong results to date and our current expectations for the fourth quarter, we have narrowed our full-year earnings projection to $2.80 to $2.85 per share from $2.75 to $2.90 per share.

Turning to slide 5, the most significant driver in the third quarter was higher retail electric revenues. This reflects the outcome of last year's Connecticut Light & Power distribution rate case and harder third quarter weather in 2015, the latter of which benefited the distribution results at NStar Electric and Public Service in New Hampshire.

Cooling degree days in Boston were up about 29% for the current quarter compared to the same period last year, and in Concorde, New Hampshire, they were up nearly 60%. You will recall that Connecticut Light & Power and Western Mass Electric both have implemented revenue decoupling, so they did not benefit from the 4.5% increase in retail electric sales that we experienced across the system this summer.

Also benefiting us in the quarter was lower O&M, which added $0.02 per share to earnings. Offsetting these gains were higher property taxes, depreciation, and amortization expense, which has been a $0.06 per share drag on earnings every quarter this year. We also had lower results in our transmission segment and in our parent and other segment.

Those segments were each down about $0.04 per share as a result of a higher effective tax rate. In the case of transmission, it was due to certain state income tax benefits in the third quarter of 2014 that did not recur this year. At the parent, as we mentioned in the earnings news release, it was the result of adjusting income tax expense to what was actually filed with our corporate tax return in the third quarter.

Turning to slide 6, for the nine-month period, higher electric revenues have added $0.34 per share to earnings. Again, this is primarily the result of the Connecticut Light & Power distribution rate case and to a lesser extent, a weather-driven 1.8% increase in retail sales. On a weather-adjusted basis, retail sales were up 0.1% through the first nine months of the year, which is consistent with our guidance.

Also benefiting year-to-date results were higher transmission segment earnings. They have added $0.05 per share and are due to a combination of higher level of investment in our system and a lower level of charges related to FERC's ongoing review of the New England transmission owners return on equity. Offsetting the impact of those benefits was the higher effective tax rate mentioned previously.

Year to date, gas segment earnings are up $13.3 million, or 30% compared with the same period of 2014. The year-to-date improvement is related primarily to a 4.8% increase in retail sales. About half that sales increase is the result of the bitter cold weather that we had in the first quarter. And the other half is related to growth in the business, with weather-adjusted firm natural gas sales up 2.5% through September.

Through September 30 of this year, we have added nearly 8,000 residential heating customers compared with just over 7,100 during the same period last year. On the non-residential side, which includes commercial, industrial and municipal customers, we've added 710 customers through September, about a 4% increase over the same nine months of last year. In terms of costs, lower non-tracked O&M has been a $0.10 per share benefit on a year-to-date basis.

We are currently doing somewhat better than expected in non-tracked O&M expense. This primarily reflects a decline in labor and labor-related costs and lower bad debt expense. Some of this is timing, so we anticipate some portion of this lower-than- expected O&M will turn around next quarter.

Also, as I mentioned on our July earnings call, the reduction in total O&M that you'll see in our income statement in the 10-Q is heightened by the sale earlier this year of E.S. Boulos, an electrical contracting company. That accounted for about $42 million of cost reductions, but that did not help the bottom line since we lost a similar amount of revenue.

Looking ahead to the fourth quarter, we expect the impact of a higher effective tax rate to continue. In 2014, our effective tax rate for the full year was about 36%. This year, we expect the full-year rate to be between 37.5% and 38%.

Additionally, you will recall that in the fourth quarter of last year, we recognized a higher equity return on our transmission assets for the refund period related to our interpretation of the FERC decision on the New England transmission ROEs. Because we don't expect to have a similar impact in the fourth quarter of this year, we expect recurring earnings in the fourth quarter to be between $0.59 and $0.64 per share, compared with $0.72 per share in the fourth quarter of 2014.

We have narrowed our full-year recurring earnings guidance to between $2.80 and $2.85 per share. This guidance shows solid earnings growth for the year and is very consistent with our targeted long-term annual growth rate of 6% to 8%. In terms of operations, our electric and natural gas delivery systems have performed very well through September 30. Our electric liability metrics, which represent the average number of months between interruptions and outage duration continue to track very favorably.

As previously reported, our reliability for 2014 was the best ever. In 2015, it's tracking even better again. So potentially another record year. In fact, looking at our performance long-term, we have experienced more than a 50% improvement in reliability over the past five years, the highest performance level ever for our systems.

Turning to regulatory items in slide 7, NStar Gas is our only distribution company with a rate case this year. On Friday, October 30, the Massachusetts DPU issued an order approving a $15.8 million increase in NStar Gas base distribution rates effective January 1, 2016. The decision approved revenue decoupling, a 9.8% ROE, a 52.1% equity ratio, and a rate base of $475 million. We continue to review the decision, but consider it a reasonable outcome.

Also in Massachusetts in August, we and the state's other electric utilities filed DPU requested proposals to modernize the state's electric grid. Our five-year plan recommends a wide range of enhancements that, among other initiatives, would increase the integration and resilience of the grid and would provide customers an option to access advance meters and provide them an opportunity to sign up for time varying rates.

The spending associated with our five-year proposal would be about $430 million, mostly capital investment, beginning in 2017. The spending would be incremental to our previously disclosed forecast. Recovery of our investments with a return would be accomplished through a new cost tracker. We expect the DP to act on our proposal next year.

In New Hampshire, hearings before the New Hampshire PUC on the divestiture of our power plants have been moved from December to January due to a lengthier discovery process. We expect a commission decision in the first quarter of 2016, completion of the plant sale by the end of 2016, and the securitization process completed in early 2017.

Now turning to slide 8, I'll provide a brief update on some significant transmission projects. Our share of the interstate reliability project in northeastern Connecticut is now 99.5% complete with a final cost we continue to estimate at $218 million.

We have also filed with the Connecticut Siting Council for five of the 27 projects included in the $350 million greater Hartford set of solutions. All five, including three substation projects, have now been approved by the Siting Council and are under construction. Together, those five projects under construction total about $100 million. We continue to estimate that all greater Hartford projects will be completed by the end of 2018.

In Massachusetts, we have increased our projected expenditures on the greater Boston reliability solution from $490 million to $544 million. As you can see from the slide, we have filed five siting applications to date and expect to be working on related projects through 2018 and into 2019. Most recently, an application for a new 345 K B-Line from [Woven] to Wakefield was filed with the Massachusetts Energy Facility Siting Board by Eversource and National Grid on September 25. It is currently estimated to cost $107 million.

All together, our capital expenditures totaled $1.3 billion in the first nine months of the year, $522 million of which was spent on our electric transmission system. At this point last year, our capital expenditures totaled $1.1 billion, of which $459 million was spent on transmission, so you can see we continue to raise our level of investment in our electric and natural gas delivery systems. We continue to project total capital expenditures of $1.85 billion this year, and will update our projections for the full years beginning with 2016 during our year-end call in February.

That concludes my formal remarks. As always, next week we will be attending the EEI Financial conference, and I hope to see many of you there. Now, I'll turn call over to Lee.

Okay. Thanks, Jim. I'll provide you with a brief update on our major capital initiatives and then return the call back to Jeff for Q&As. Let's start with Northern Pass in slide 10.

On August 18, we announced our Forward New Hampshire plan, which included substantial revisions to our recommended route. Most of those route changes involved the central section of the project, where we are now proposing to build 52 miles of the project underground rather than overhead along existing transmission rights of way.

We have also downsized the project from 1,200-megawatts to 1,090-megawatts as a result of our plans to use a different DC technology that carries less power and is less costly to install. For much of the overhead section, we are also proposing to use [many more manifolds] rather than traditional lattice towers to reduce the visual impact. Additionally, as part of our Forward New Hampshire plan, we announced our intent to provide $200 million of support to the state over the next 20 years to support important initiatives in tourism, economic development, community investment, and clean energy innovation, should Northern Pass be built and placed into operation.

We've had a very positive reaction to the Forward New Hampshire plan, which has now been endorsed by a wide range of business, labor and political leaders, both state and municipal in New Hampshire. We held five public meetings on the project in the state in early September and filed our siting application with the New Hampshire Site Evaluation committee on October 19.

The filing highlights the significant direct benefits the project will bring to New Hampshire, which we estimate to be more than $3 billion. They include $80 million per year of lower energy costs over the next 10 years, $30 million per year of increased property tax revenues, and $2 billion of increased economic activity, driven in part by the creation of 2,400 jobs during the construction period.

The benefits also include reducing the regions carbon emissions by approximately three million tons per year. We have illustrated that the carbon reduction requirements of the three states we serve on slide 11.

The challenge the region faces meeting those requirements were made more difficult last month, when Entergy announced it will retire the Pilgrim nuclear power plant no later than June of 2019. That shutdown, in and of itself, is expected to increase carbon emissions by two million to three million tons a year. The closure of Vermont Yankee nearly a year ago increased carbon emissions by a similar amount.

This is a particular issue for Massachusetts, which is targeting a greenhouse gas emissions goal of 71 million tons by 2025, a reduction of 23 million tons from the 94 million tons emitted in 1990. Massachusetts plans to achieve 10 million tons of that reduction from the electric power sector and more than half of that is expected to come from the new clean energy sources such as Canadian hydropower. But the state's efforts will clearly be challenged by the impact of Pilgrim's retirement.

Governor Baker filed legislation this past summer that calls on the state to purchase up to 18.9 million-megawatt hours annually of clean hydroelectric power and other renewable energy. That equates to about 2,400-megawatts of capacity. He personally testified on behalf of the bill in September. We will closely monitor its progress.

All of these developments point to the significant need the region has for Northern Pass. It would represent the largest single new source of clean, firm power available to the region.

Turning to slide 12, let's talk about our next steps on Northern Pass. On the state side, the New Hampshire SEC has until mid-December to determine whether the application we filed last month is complete. Once it makes that finding, the site evaluation committee will then have up to 12 months to conclude its review and vote on the project application.

During that period, there will continue to be significant opportunities for public input. Early in that 12-month review process, Northern Pass will host another round of public information sessions about the project and the New Hampshire SEC will hold its own round of public comment sessions. The state process will run in parallel to the federal process.

The DOE is currently preparing a supplement to the draft EIS to reflect the changes we announced on August 18 and has indicated that it will complete that supplement this month. As a result, we expect the DOE to hold public hearings in New Hampshire in December to receive public inputs on the draft EIS. DOE already has asked that written comments on the draft be filed by the end of this year.

With that information in hand, the DOE will work to finalize the EIS, perhaps in the third quarter of next year and later issue a presidential permit for the project. We believe that the federal permit issuance will occur shortly after the state process concludes to ensure that the permits reflect the same project configuration as approved by the state of New Hampshire.

We expect to commence construction activities in early 2017 and largely conclude them around the end of 2018. As I've said previously, final testing of the project is expected in the spring of 2019, when electric loads in New England and Quebec are relatively low.

As we announced in mid-October, we expect the project to cost approximately $1.6 billion, somewhat higher than our $1.4 billion price tag we noted previously. This is due largely to the additional excavation costs associated with the incremental undergrounding. You have probably seen multiple comments from Hydro-Quebec since July, reiterating their support for this project and noting that they have commenced siting activities for their transmission and substation construction on their side of the border. Our partnership remains extremely strong because of the enormous benefits this project brings to both sides of the border.

As we have discussed previously, we expect Northern Pass to bid into the Joint Clean Energy RFP that Massachusetts, Connecticut and Rhode Island first announced in February. As you can see on Slide 13, Rhode Island regulators approved the RFP for issuance in September and the Massachusetts DPU approved it last week.

Once the Connecticut Department of Energy environmental protection signs off on the RFP, we expect it will be issued promptly. Once the RFP is issued, we expect the states will look for bids within approximately 75 days with an evaluation period to follow. We are very optimistic about the chances of Northern Pass in such a competitive solicitation.

Turning from Northern Pass to our other large project, Access Northeast in slide 14, we and our partners Spectra Energy and National Grid, will submit our prefiling application with the Federal Energy Regulatory Commission later today. The filing will describe the scope of the project and will commence a dialogue between the project, FERC staff and key stakeholders in the process, which includes soliciting public comment.

Both Access Northeast and Northern Pass are critical projects in our region's efforts to address serious infrastructure challenges that are driving up wintertime energy costs and challenging grid reliability and our ability to meet legislatively established renewable energy in carbon reduction targets. Access Northeast will allow us to keep 5,000-megawatts of efficient natural gas generation online, even during the coldest winter evenings.

As you recall, the primary business model for access northeast is that the region's electric distribution companies will contract for long-term natural gas capacity and then hire a third party to re-sell the capacity in the short-term market to generators. Together, the expansion of the Algonquin system and the construction of 6.8 billion cubic feet of LNG storage at our existing facility in Acushnet, Massachusetts, would provide enough gas to generators so that the wintertime electricity costs should drop by approximately a $1 billion a year in New England and up to $2.5 billion in a winter like we had in 2013 and 2014.

The Access Northeast project is ideally suited to address the [windwood] natural gas infrastructure challenges since it would involve upgrading Spectra Energy's existing pipelines in New England. Our project is uniquely situated to deliver increased quantities of natural gas to the region's newest and cleanest fossil generators. To remind you, Spectra and Eversource each own 40% of the project and National Grid owns 20%.

We believe that most of New England states will allow their electric utilities to participate in the natural gas capacity solicitation. During our July earnings call, I summarized the process.

Turning to slide 15, I will provide the update of activity over the past three months. In Connecticut, the Department of Energy and environmental protection is expected to launch a gas capacity solicitation late this year. In New Hampshire, the PUC staff issued a report on September 15 in which they concluded that the state utility regulators have the authority to approve such contracts, as long as they are proven to have a consumer benefit.

Comments on that report were filed with the New Hampshire PUC in mid-October. In Massachusetts, the DP ruled October 2 it has statutory authority to approve capacity contracts signed by electric distribution companies. Electric utilities of Eversource and National Grid in Massachusetts and Rhode Island launched a gas capacity open solicitation with proposals due November 13.

In Maine, the Central Maine Power recently submitted comments to the Maine commission recommending the state proceeding to be expanded to consider regional solutions, including in particular Access Northeast. We remain optimistic that we will be able to file contracts with state regulators by the end of this year or early next year and have them approved by the middle of 2016. We expect to make our formal filing on FERC later in 2016 and expect to bring major sections of the pipeline into service for the winter of 2018, 2019, assuming expeditious approvals by federal and state authorities. Because of the longer construction time line for LNG facilities, we anticipate the storage element of the project to commence service after the pipeline.

So now what I would like to do is turn the call back over to Jeff for Q&A.

Thank you, Lee. I'm going to turn it back to Brandon to remind you how to enter questions. Brandon?

Thank you.

(Operator Instructions)

Thank you, Brandon. First question this morning is from Julian Dumoulin-Smith from UBS. Good morning.

Good morning, Jeff; good morning, Jim.

Good morning.

Perhaps first quick question, if you will. Obviously, with developments at Pilgrim, they have ramifications. You kind of alluded to them. I would be specifically interested in how does it impact transmission planning at ISO New England and could we see that flow through here in the next year?

And then separately, could you speak to the wider procurement process and how the carbon impact could drive specifically procurement for your solution effort? How is that going to tangibly have the impact on Northern Pass?

Okay. Just in your first question, I think you asked in regards to Pilgrim retiring. One of the things that we're doing now is we're doing our system modeling around the impacts of Pilgrim retiring and understanding what that means to our reliability in that region. Of course, ISO New England does this as well.

And we haven't quite completed that. We expect there will be some upgrades as a result of Pilgrim retiring, but we don't see those upgrades at this particular time as being significant upgrades in terms of CapEx.

In regards to Northern Pass and the carbon mandate, clearly right now as a result of Pilgrim retiring -- and the stat is that Pilgrim produced 84% of all of Massachusetts non-carbon energy, about 84%, so Massachusetts has very aggressive goals in carbon reduction, as I've stated, and as you can see on the slide. And the governor, Governor Baker, has said that he intends to meet the goals that the previous administrations have put in place and that one of the ways to do that is by having large amounts of Canadian hydropower delivered to the region.

And, one would assume that in the case of Massachusetts, they see part of their solution being with a hydropower. And, of course, the difference between hydropower and wind is hydropower is firm. You know, you can book it. You can schedule it. You can add up the numbers and determine the carbon impact of that and you can clearly place those against your goals. So we think carbon will be a significant attribute in which the state will be looking for as part of a three-state RFP.

Got it. And then just quickly following up on the developments on the EIF, does the need to refile impact at all your negotiations in New Hampshire? Or does that reset any processes, as far as that's going?

No, no. We've had a period of a couple years of really significant outreach into the communities with key stakeholders in the state, political leaders. We think we have a route that works. That is captured in our filing.

And, of course, as always, when you go through siting, there is always some local mitigation that a siting council would put in place. But we don't feel that would be significant, or have a significant impact to the project.

But to be clear, the settlement conversations with New Hampshire continue?

We actually have no settlement conversations with New Hampshire. We have provided our forward New Hampshire plan, which really outlines our benefits to the state. Those have been extremely well-received by everyone from the governor to key legislative leaders in the business community. So we're not in a process of negotiating settlement. We believe that a litigated outcome here through the process is the best outcome and is an outcome that will stand up to scrutiny post the decision.

Great. Thank you.

Thank you, Julian.

Next question is from [Shaw Pourreza] from Guggenheim. Good morning, Shaw.

Good morning, Jeff; good morning, Team.

Good morning.

One question only on Northern Pass. Maybe we could touch on TDI's competing proposal. Obviously, Clean Power Link has a similar COD, they sort of jumped ahead with the final EIS, but then like you touched on, on the prepared remarks, you're dealing with the Vermont Yankee shutdown, the recent Pilgrim decision, you've got the clean power plant, obviously infrastructure issues, the governor's bill. So should we think about these projects as sort of mutually exclusive? Can they coexist? How should we think about that?

Well, I think in regards to the first part of your question, in regards to TDI, TDI -- I won't speak for them, but they will have to line up a source of energy in which they could sell over that line and the energy at least from Hydro-Quebec, from their hydro facilities will come through the Northern Pass line.

We have a contract with them that we have worked out several years ago and they are currently in the siting process, which is actually a fairly lengthy process in Quebec. It's about a three-year process. They are in that process with us at the site, transmission line, major substation, a converter in Quebec, and are engaged in no other siting, no other siting activities. So from the standpoint of GDI, their power's not coming from Hydro-Quebec. They would have to find another source of power.

If you look at the other various projects, there will be a number of projects that will be bid into the three-state RFP and perhaps even including another project by Eversource that we are working on development at this point in time. So there will be a number of those projects and the states that participate in the process will have to look at those to understand what is the most beneficial net present value for customers, what projects are indeed sitable and the credibility of the counter parties that would be building them. So that's I think the rationale there.

Okay. Thanks so much.

All right. Thanks, Shaw.

Next question is from Dan Eggers from Credit Suisse. Good morning, Dan.

Good morning, guys. Just could we follow up a little bit on this Massachusetts electric grid modernization program, and just kind of what was the genesis of these projects, kind of the nature of what you're going to do there and when next year do you expect to get some sort of visibility on spending for those projects?

Sure. I think as my comments indicated, the spending is expected to be about $430 million. And there's a series of components. We filed this back in mid-August, but kind of next generation, remote fault circuit indicators, improvements to allow distribution, management of the distribution system, predictive outage protection, that sort of thing.

So a lot of focus in the industry about making the grid more modern, smarter, more capable to accommodate distributed resources, so much of the spending is along the lines to achieve that. And, again, the budget we've submitted is a $430 million number.

And the process for the commission to say yes on this and set the mechanism so you get more timely recovery, what process are we looking at for that?

Well, the, the process came out of the generic proceeding at the Mass DPU where the utilities were encouraged to file these plans. The utilities in Massachusetts did file them this year and the expectation is that this -- they will be reviewed and assessed and hopefully approved within the next year.

Okay.

Hopefully early 2016.

Early 2016, okay. And then I guess you're kind of looking at the Pilgrim implications. Entergy is talking about no later than 2019. Some of your big projects are coming at that 2018-2019 crux point as well. How do you guys look at system reliability? And is there going to be a more meaningful shortfall of resource if you can't get Northern Pass or the [Nesco] pipes done on the time lines you guys provided today?

Well, just looking at system planning in that period of time, in the 2017 period, you will have a breaking point will be gone, which is 1,500-, 1600-megawatts of coal-fired generation, which has played a pivotal role during these winter periods. That will be gone. Pilgrim will be gone in the 2019 timeframe.

So it's really imperative that we get our Access Northeast project phased in starting in the winter of 2018-2019, and that is clearly one of the points that we're making the key policy makers, including regulators. So to the extent that we don't have some amount of that gas flowing in, then this system could be very, very tight in terms of reliability, which what will it mean is that existing plants that can dual fuel and burn oil will probably burn a lot more oil like they did in the winter of 2013-2014. So things could be very, very tight during that period.

Just one last one, if you think about the approvals you need for the Nesco to get done, where do you -- where are you most nervous right now about being able to hit the 2018-2019 targets?

For Access Northeast, I mean, we need to go through this open solicitation that we have in Connecticut and Rhode Island. We need to have Connecticut, which is going to go through its own state-managed RFP. We need that to happen.

Really what happens is that after you go through and you get them approved, you've got to get the PUCs that will approve these contracts and the regulatory time line in each of these states is a little bit different. Connecticut is going later, but has a very, very short regulatory time line, turnaround. It's usually about 60 days, so they actually may go later, but finish first. Massachusetts has a longer time line.

So we expect all of these things to come together late this year, early next year, and determine who the winners of this open solicitation and RFP is. In some states such as Maine, New Hampshire, it may just be filing a precedent agreements in the states that have the PUC approve. Meanwhile, in parallel, we'll later today file our FERC prefiling. That really opens up a complete process of 13 separate individual reports that we will file. The whole idea of that FERC prefiling process is to try to reach alignment around the end of it, which takes about a year, such that we file the final agreement with FERC, the review process can be expedited. So really right now it's a combination of getting through the state process and then supporting the FERC prefiling process.

Got it. Thank you very much.

All right. Thanks, Dan.

Next question is from Ashar Kahn from Visium. Good morning, Ashar.

Good morning. How are you guys doing?

Good morning.

I was just trying to -- right, we're running LTM to [94] and the guidance this morning has been the midpoint is, if I'm right, [283]. So we're going to lose, as you said, in the fourth quarter around $0.11 or so. Can you just tell us in which buckets the earnings decline is going to come in? Is it going to be the distribution, generation side, where a majority of the shortfall is going to happen in the fourth quarter?

I was just trying to pin in my -- the results as to where should we see the shortfalls, in which segments of the business in the fourth quarter?

Sure. If you look at the fourth quarter of the year ago, there were a couple of unusual items. One had to do -- I guess combined probably total of about $0.09. It's got to do with what we've booked related to the FERC ROE case.

So that would be in the transmission space. That's probably half that number, half the $0.09 number. And the other half would be the change that we've seen in income taxes between the two quarters, the fourth quarter year ago and the one that we expect coming up. Obviously, that would be spread across each of the segments.

Okay. Okay. Appreciate it. And then, Jim, can you just -- as you have mentioned, as we look into 2016, and the 6% to 8% growth rate, as you mentioned, some of the spending on the pipe because of the approval process of the Pass will be shifted.

Will that lead to like -- to be us at the lower end of that growth rate target next year? I'm just trying to see -- or can we find stuff to replace that shifting of some of that transition spending as we look into next year?

Sure. Just to calibrate where we are this year, if you look at the range we provided in the release yesterday and then today, the bottom end of that range, $2.80 would be about a 6% growth in earnings over last year. The high end of that range, $2.85 would be an 8% growth over where we were last year. So again, very consistent with the 6% to 8% growth that we have provided long-term.

Obviously, we're into the 2016 budgeting process. I do feel good about where we are, but we haven't wrapped it up yet. We tend to finish it with a Board approval in early December. We like to start the year with an improved plan, but we do have continued transmission investment. We do see O&M reduction opportunities again next year. We've got new gas distribution rates that will kick in at NStar Gas effective January 1. The rate increase that I mentioned.

We continue to see vibrant growth in the number of customers on the gas side, the conversions seem to be going pretty well. So those have been the factors that have been drivers for our earnings growth over the last couple of years. And many of them continue into 2016.

Okay. Okay. Appreciate it. Thank you so much.

You're welcome. Thanks, Ashar.

Our next question is from Travis Miller from Morningstar. Good morning, Travis.

Good morning. Thank you. I was wondering, on the electric businesses, and specifically, can you give us a glide path, so to speak, of earned ROEs, where you're starting at this year and then some of the key factors. Obviously, there's net new investment. But what would be the elements that might keep those earned returns in that allowed return range for the next two to three years without having to file rate cases? Just wondering if you could give a sense for that glide path and the variables there for the electric business.

Sure. Well, the gas business, the one subsidiary that we were significantly underearning on was NStar Gas, and obviously, the order that we received Friday improved our ability to earn there. We generally forecast pretty flat sales growth on the electric side, 0% to 0.5% is the guidance we're giving long-term. A couple of our electric subsidiaries have decoupling, so sales growth is largely irrelevant.

So we have an opportunity to continue to grow earnings either through some of these trackers that we're putting in place or through continued cost cutting. And we are doing much better, I would say, because of the cost cutting that we've been able to implement in terms of allowed ROEs. We continue to operate within the dead band, or sharing mechanisms that we have in place. And they continue to generally improve year in, year out.

Okay. That's all I had. Thanks so much.

Thanks, Travis. Next question is from Caroline Bone of Deutsche Bank. Good morning, Caroline.

Good morning. So I was wondering if you could talk a little bit more about this other transmission project that you guys are working on that might fit into the three-state RFP and what this might look like and when it might be eligible to come into service.

Caroline, this is Lee. At this time, I really can't disclose more on that. We're still working with our partners, trying to firm up what that partnership would be and how that would work. But I would say that's going well and I think once we get farther down the road on that, we will look to disclose the partners and projects. I just can't disclose anything on it at this point in time.

Okay. That's fair. Then I guess just actually a specific question on the three-state Clean Energy RFP, you mentioned, I believe, that Northern Pass is going to participate. But I didn't think that NPT could participate in the stage because I didn't think large scale hydro qualifies under the current law in Massachusetts. Has something changed there or maybe I was misunderstanding how it worked.

The RFP has three provisions in which you can bid on. One is just doing a power purchase agreement. The second one is doing a power purchase agreement with transmission. So you could bundle them together. And the third one was called a deliverability commitment, which means that you would build transmission to an energy source and that source of energy would make a commitment to flow X amount of energy over the course of a year, so in terms of megawatt hours.

And, of course, particularly for carbon, you would want a source of energy that's large, that is firm, that is dispatchable. So that's kind of the -- that's the three ways in which the project could participate. In the case of Connecticut, there's probably about 250 or 300megawatts of hydropower that could be purchased by Connecticut. And then all three states have agreed to the deliverability commitment.

All right. Thanks very much, guys.

All right. Thanks, Caroline.

Next question is from Greg Gordon from Evercore ISI. Good morning, Greg.

Thanks. How are you doing, guys?

Hi, Greg.

So just going back to -- I was going back through time and just looking for the last official update you gave on your CapEx projections through 2018. And I believe it was in your April presentation for the spring utility day for some other -- for some broker. And I'm just -- you've given kind of an update qualitatively on what you're looking at in terms of the evolution of the CapEx plan.

You have a slide out of page 8 where you give an update on all the major transmission reliability projects and you talk about other stuff. Could you just talk about whether this $3.9 billion CapEx plan that you last gave us, if you're basically telling us there's an upside bias to that plan because of the things that you identified that would enhance customers' reliability or whether the -- there was a placeholder in that plan already for a lot of this stuff or somewhere in between?

Greg, I think what you're referencing is when we did our end of the year call back in February of 2015. We used the same numbers and CapEx projections that we then embodied in our 10-K. So that's the annual update.

Sure. I think -- not to fully reconcile, but what's changed since then, I think the grid modernization plan that I mentioned earlier that's under review at the mass DPU, the $430 million of spending associated with that. Obviously, the cost of Northern Pass has increased and we've disclosed the new price went from $1.4 billion to $1.6 billion.

Our increases in the greater Boston reliability solution that I alluded to in my comments as well, and Lee mentioned that there may be other transmission projects that we're looking at now that we haven't quantified or disclosed at this stage. But the progress has generally been increased spending in transmission over what was provided earlier -- transmission or distribution over what was provided earlier in the year.

Great. Thanks. That's pretty clear. The only reason I asked was because there is one section of those bar charts that says $968 million of other forecasted reliability projects that aren't specifically called out. You're saying that all the stuff you just delineated would have been upsides to what you thought you were going to spend when you put out this plan?

That bucket tends to be many, many smaller projects, each which of are identified and estimated. But those projects are still in the plan going forward.

Okay. That's very clear. Thank you, guys.

You're welcome, Greg.

Thanks, Greg.

Next question's from Michael Lapides from Goldman. Good morning, Michael.

Hi, guys. Congratulations and congrats on the run the Patriots are having up there. Real quick, when you think about the CapEx schedule, so not the total amount, but the timing for both Northern Pass and Access Northeast relative to what you had back in the K, where are you schedule-wise versus where you originally thought you would be nine or 10 months ago?

Well, we really haven't disclosed, I don't think, Northern Pass capital expenditures spending by year in the 10-K. I think from the period of the 10-K, I think now that we have a new schedule that we have a high degree of confidence in, there has been some slippage over where we were a year ago on Northern Pass. So some of the spending that we had in 2016 has shifted into 2017. And similarly, some of the 2017 spending into 2018.

So we intend to provide a refreshed and new capital outlook, as we usually do after our year end results are published in February. But no, no major changes other than I would say that the new Northern Pass time line.

Got it. On Access Northeast, just in terms of how you're thinking about the time line for construction, kind of year-over-year relative to what you had originally put out in numbers a while ago?

Michael, just to be clear, we never showed numbers year by year for Access Northeast. We've always said that was in addition to the forecast that we laid out in February.

Got it. Thank you.

And just generally speaking, because we haven't really laid out the numbers and I think we'll be in a better position in the February timeframe to give you a better look at those. If you look out between the prefiling and the FERC final filing, which will take place next year, over this period of time it's really all environmental work and engineering work, study work and so forth. And then we would expect to get, after we do our final filing with FERC in November of next year, we would expect to get a decision out of FERC in the essentially spring of 2018, so we'll say April timeframe.

And then we would start construction and we would have the first phase of the project in for the winter of 2018-2019. And then the next year the majority of the pipeline, and then the LNG facility will phase in late in 2020 and 2021.

Got it. Okay, guys. Last question, totally unrelated, when you think about the impact of O&M management and the ability to continue to reap O&M cost savings, where do you think you are in the process? Meaning do you feel like you've realized a large chunk of the post merger O&M savings at this point? Do you see yourself as still having huge runway or do you expect that runway to kind of slow down a little bit in terms of the ability to realize cost savings over the next few years?

I think the guidance that we gave is that we do think we can achieve on average 3% reductions right through 2018. Obviously, as you know, Michael, we have delivered on those estimates. I would say that, early on, clearly identifiable merger-related savings are very obvious post-merger. But at some point you transition from merger-related savings to just best practices and good cost discipline throughout the organization.

So I think that's the phase that we enter now as the classic merger-related items become fewer and fewer the further you get away from that merger date. So we continue to be optimistic about the guidance that we've provided and we'll refresh in February again for everybody.

Got it. Thanks, guys. Much appreciate it.

Thanks, Michael.

Next question is from Paul Patterson from Glenrock. Good morning, Paul.

Good morning. Just quickly, on Northern Pass and the forward capacity auction on number -- when do you think that we'll actually see it fit into the FCA?

That is probably not in the immediate future. It's really kind of an HQ decision because they would bid that into the forward capacity market. So I don't think you'll see anything this year, early in the next auction, which I think is in February. So it's a ways out.

Okay. And the reason for that? Can you--

The reason for that is obviously you make the commitments into like, for instance, the 2019-2020 timeframe, you make that commitment. You got to cover the commitment. If for some reason there is a delay as a result of siting or if there -- we still have to do some work with ISO New England in the market monitor and so forth, so we still have some technical issues, market issues to work out through them.

So you want to get farther along in those discussions. You want to have a better sense around where the siting process is before you commit to like 1,100-megawatts into the marketplace and you got to have a line to deliver it.

Okay. And then on the modernization project in Massachusetts, advanced meters, you sort of mentioned it as being optional in the slide. And I was just wondering, you guys have had a more conservative approach toward meters, I believe, in the past. What do you think the adoption rate -- or how much of that CapEx do you guys associate with advanced meters in that proposal that you have there?

Well, there is the ability to opt in included in our proposal, which on means that we're not suggesting that AMI should be spread around our entire customer base. I think the details of the filing are available, in addition to the meters and it is also sort of IT system changes that would be needed to accommodate time-varied rates. So the detail is in our filing, I believe, but I don't have the number readily available, Paul.

Okay, sure. But would you say that you guys are still cautious, it would seem, am I wrong, in terms of the benefits that advanced meters are likely to provide? I mean, it doesn't seem like -- is that a fair characterization?

Yes, we believe that there are some people that may be interested in monitoring their usage very closely, on a daily basis if need be, and for that group of people we will allow the option to give them the infrastructure to do that. But we think that it's a very small minority of our customer base overall.

Okay. Thanks a lot.

All right. Thank you, Paul.

Next question's from Andrew Weisel from Macquarie. Good morning, Andrew.

Good morning, everyone.

Good morning, Andrew.

First question on some of the public hearings you've had for Northern Pass, how would you say the feedback you've received from those meetings went and how might that affect the SEC review? Media reports suggest they weren't the most favorable conversations.

Yes, I would say that there was a range. There were five meetings in five different locations. I actually think we did six in five locations. But clearly in the northern part of New Hampshire, we had the most vociferous group of folks there. But at the same time, the demeanor was different. It was respectful. There was less emotion. There were -- there's always going to be the hard core opponents to it, but I would say there was more dialogue this time.

I would say it was informative. We had some of the other meetings really where just a handful of people showed up they really don't have that concern. And so it was a range, but I will say it's markedly different from the open houses that we've had in New Hampshire before around this line, a whole lot less emotion, and some mutual respect between the presenters and in the audience. I really think it was very, very well done.

Sounds good. Thank you. Next question on the Massachusetts modernization plan, might be too early, but would you have any sense what the shape of that $430 million might look like? In other words, would it be even spending each of the five years or so or maybe more front end or back end loaded?

I think probably -- what I should point out maybe a third of it is going to be O&M. Only about two-thirds of it is capital spending. And I do think it ramps up during the five-year period somewhat.

Okay. Then just two last questions as we look forward to 2016 earnings. Obviously, you haven't given guidance yet, but the first question I have is on tax rates, if you have any kind of forecast for what an effective tax rate might be relative to this year.

And then second, on the FERC ROE, the ALJ should give their recommendation before you give your 2016 guidance. Would you somehow reflect that in terms of the transmission ROE or wait for a FERC decision later in 2016 before you start to accrue those numbers?

Sure. On the second one, it will depend upon the facts and circumstances of the FERC ROE order, whether or not we would reflect anything associated with the ALJ recommendation, or whether we would wait until the FERC final decision, which we expect in the third quarter of 2016. We continue to believe that the base ROE that was allowed in the first complaint, 10.57%, is well within the range of reasonableness going forward. So we would hope and expect that the FERC would come to a similar conclusion.

In terms of the effective tax rate, as I mentioned, this year we expect to be between 37.5% and 38% and I'm going to not provide a number for 2016 until we provide our guidance in February.

Fair enough. Thank you very much.

You're welcome, Andrew.

Thank you, Andrew. That's the last question. So we want to thank you folks very much for joining us today. As Jim said earlier, we'll see many of you down at EEI starting on Sunday. Safe travels. And we look forward to seeing you there. Thank you very much.

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