康涅狄格電力 (ES) 2015 Q4 法說會逐字稿

Welcome to the Eversource Energy fourth-quarter earnings call.

My name is John and I'll be your operator for today's call.

(Operator Instructions)

Please note the conference is being recorded.

I would now like to turn the call over to your host, Jeff Kotkin.

Thank you, John.

Good morning, and thank you for joining us.

I've Jeff Kotkin, Eversource Energy's Vice President for Investor Relations.

We posted slides last night on our website that we will reference during our remarks today, and as you can see on slide 1, some of the statements made during this investor call may be forward-looking as defined within the meaning of 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 the 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 September 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 on our website under Presentations and Webcasts, and in our most recent 10-K and 10-Q.

Turning to slide 2, speaking today will be Tom May, our Chairman, President, and CEO; Lee Olivier, our Executive Vice President for Enterprise Energy, Strategy and Business Development; and Jim Judge, our Executive Vice President and CFO.

Also joining us today are Werner Schweiger, our Executive Vice President and COO; Phil Lembo, our Vice President and Treasurer; Jay Buth, our Vice President and Controller; and John Moreira, our Vice President of Financial Planning and Analysis.

Now I'll turn over the call to Tom and slide 3.

Good morning, everyone.

I have the easy job this morning of making the introductions, and let me start by saying surprise, surprise, we had another great year.

Jim, in a minute, will take you through all the numbers to explain that, and Lee will take you through the significant big capital projects that we have, and they will both report on great progress.

We're moving along quite nicely.

One of the things that we have been focusing on for the last four years is customer service.

Those of you that know me, I'm a nut about customer service, and I think that in 2016, operationally, we had the best-ever year, with record reliability, the record number of customers we were able to connect into our gas system, and we think we did that at a time when the delivery part of our bills have been very, very stable.

In 2016, we think we're going to bring it to the next level.

We're focused on the customer touch points.

We have successfully implemented a new outage management system throughout the three states, so that, if you will, our order entry system is consistent for all 3.5 million of our customers.

With this technology, which has great connectivity between our customers and our electrical components, we're going to be able to take it to the next level with a communications strategy that will let the customers know exactly what's going on at all times with their system and their connections.

We're also going to be rolling out a new bill, new website.

Again, important interactions with the customer that we think are the key to our success long term.

For the region, as you know, it's an exciting time in New England.

We are in a very unique phase.

I think, just last week, Gordon van Welie, who runs ISO New England, made a great presentation to the business community, and its focus was the needs going forward.

And critical first thing that he addressed is the gas infrastructure needs, showed the difference between our pricing and New England -- excuse me, and New York and other regions in the winter time frames when our gas infrastructure experiences constraints.

And whether gas prices are high or gas prices are low, the differential is very significant.

He also talked about the transmission system and the impacts that are going to be felt as we, as a region, meet our carbon-reduction goals, and move almost 35% -- or more than 35% of our fossil generation over to renewable generation.

So, exciting time, and we're right in the middle of that and we'll talk more about that.

For investors, of course, you know that we work for you.

The foundation for TSR, which we measure very carefully, is growing earnings per share and growing dividends, and that's what we'll talk to you about -- our ability to continue that as we go forward.

And, as we do that, we think we will provide attractive returns, while maintaining the highest credit rating in the industry.

If you flip to page 4, my favorite slide in the deck, we continue to outperform our peers in the market over the long term.

Last year was a flat year.

We do believe we did better than the industry and, as you can see by the bottom chart, as long as we keep our dividends growing -- and this week we raised our dividend 6.6%, or $0.11 -- and, despite that, we still, as you know, have a very modest payout ratio.

I won't dwell on those numbers, although I do like to.

The last slide I just would mention before I turn it over to Lee is page 5, and we're really quite proud of this.

We've grown into a role as a regional leader.

I referenced the recent ISO New England presentation that Gordon made, and their view on the regional challenges.

But what has been very interesting -- and Lee is in the center of all of this -- that, as the largest player in New England, we seem to be the one that everybody comes to, when they think they can help our customers in the region achieve our energy goals.

So, we're working with several partners to help create the solutions that will bring us to the modern era.

Whether that's the pipeline constraints that I mentioned, again, we think we have the best project and the best partner in the form of Spectra Energy that allows us to use existing facilities that pass by every one of our most efficient new gas-fired units in New England.

And, with our plan, we'll keep those units in the competitive queue each and every day of the winter.

On the renewable energy side, we think we have -- and there we'll probably talk about the three-state RFP, but as we look at that, we think we have the only dispatchable project that can flow a substantial amount -- no pun intended -- of carbon-free energy into the region at the peak times that will, again, affect pricing in the queue.

Whether it's the oil heat dependency that, in particular, in Connecticut is a key program in the Connecticut energy policy, we found this year that, despite the fact that the gap between oil and gas shrunk considerably, that people still want to convert, and we were able to convert about 11,000 customers last year.

And I think we already converted 1,000 in January.

So, the mild weather, while we don't like it from a sales perspective, allows us to continue and get a lot of work done.

And, of course, the forefront of everything in New England in terms of solving our energy problems and backing out carbon, is energy efficiency.

It's the cheapest way to achieve our objective.

We have award-winning EE programs, as the slide says.

We spend $0.5 billion a year.

But, last year, we actually exceeded our goals, spent less, exceeded our megawatt-hour goals and had our incentives -- we exceeded our plan by about $5 million on the incentive side.

So, we're very proud of that.

The bottom line is, we want our customers to see us as the solution to their energy concerns, and that's why it's an exciting place to be, New England, and for us to be in the center of all this.

And, with that, I know you would like to hear more about the projects.

Every time I'm in front of a group, they want to ask about Northern Pass or Access Northeast.

Even my Board is always interested in what's going on with the projects.

So, with that, I'll hand it over to Lee to give you more flavor on -- and a progress report on where we are with some of this stuff.

Okay.

Thank you, Tom.

I'll provide you with a brief update on our major investment initiatives, and then turn the call over to Jim.

Let's start with Northern Pass and slide 7. In December, the New Hampshire Site Evaluation Committee, or SEC, determined that our Northern Pass application is complete, and commenced the formal review process.

As part of that process, the SEC held five public information sessions on the project in January, and will hold another round of public hearings later this quarter.

Simultaneously, we continue to respond to questions about the project from the multiple state agencies that are participating in the review.

As you can see from slide 8, we expect the New Hampshire SEC to vote on the Northern Pass, consistent with its current schedule, which concludes on December 19.

In parallel, the US Department of Energy will host a series of four public hearings on its draft environmental impact statement, or EIS, on Northern Pass the week of March 7. Two of them will be held jointly with the New Hampshire Site Evaluation Committee.

Written comments on the draft EIS are due to the DOE by April 4. We expect the DOE to finalize the EIS in the second half of this year, and anticipate a Presidential Permit issued soon after the New Hampshire SEC process has concluded.

That timetable has not changed and will ensure that all relevant conditions of the SEC decision will be reflected in the Presidential Permit as well.

We continue to feel very good about the review process in Northern Pass.

We are receiving strong support for the project, both inside and outside of New Hampshire.

At the first public information session last month in Franklin, New Hampshire, where the DC-to-AC converter station will be located, we received significant support from local leaders, the business community, and labor representatives.

In Massachusetts, Governor Baker said in his State of the State speech last month that increasing access to affordable hydroelectric power was a top priority of his administration.

As Jim will discuss in a few moments, our new capital expenditures forecast reflects the revised $1.6 billion of cost of the project we announced in October, and it also allows the vast majority of the construction to take place in 2017 and 2018.

As you probably know, Northern Pass is one of two projects connected to Eversource, that were built into the bid into the joint state RFP.

As shown on slide 9, the other project is the Clean Energy Connect.

This project involves construction of a new 600-megawatt, 25-mile transmission line between a transmission substation we own in Hinsdale, Massachusetts, and a transmission substation in Easton, New York state.

This project will utilize a back-to-back HVDC converters to ensure deliverability into New England.

We are developing it with Brookfield, an [e-patroller] and EDP Renewables.

These partners already have a presence in New York, have not been specific about the costs, but our share, which is entirely a transmission investment, will be more than $400 million.

If approved as part of the RFP, we would expect this project to be built in the 2018 through 2020 time frame, and for our investment to earn returns consistent with FERC-regulated transmission investments.

Each of the three states involved in the Clean Energy RFP -- Massachusetts, Connecticut, and Rhode Island -- will go through a process to select the winning bids, and submit them to regulators for approval.

The RFP schedule is on slide 10.

As you can see, we expect contracts with the successful bidders to be executed by the end of the third quarter, and for the contracts to be approved by the end of this year.

We believe that the two projects we are jointly proposing represent the region's best options for low-cost, firm, reliable, and non-carbon-emitting resources.

Regarding Northern Pass, our bids into the RFP does not change in any respect the significant benefits this project will provide to the host state of New Hampshire.

Our forward New Hampshire plan remains in place.

We anticipate $80 million per year in energy savings to New Hampshire, additional savings specific to New Hampshire as a result of a power purchase agreement with HQ, a commitment to hire New Hampshire workers first, a $200 million fund to support economic development and community initiatives, as well as other benefits.

I'll now turn to slide 11 and the Access Northeast project we plan to build with our partners, Spectra Energy and National Grid.

To remind you, Access Northeast is a $3 billion project to upgrade the existing Algonquin pipeline and add 6.8 billion cubic feet of LNG storage in Acushnet, Massachusetts, to bring firm gas supplies to power generators in New England.

Our share of the Access Northeast project is 40%, or $1.2 billion.

FERC has accepted the pre-filing we made last year, and we are continuing to submit information on the project to FERC as part of that process.

In January, staff completed 13 -- FERC staff completed 13 open houses on the project in the region.

We plan to make our formal application filing late this year to meet our initial in-service date of 2018.

The project is designed to add 900 million cubic feet per day of natural gas supplies to serve the region's power generators during cold winter periods.

That will allow up to 5,000 additional megawatts of the region's most efficient and low-cost units to remain online when winter temperatures drop, saving New England customers approximately $1.5 billion to $2 billion in a typical winter, and approximately $3 billion in an extreme winter such as 2013/2014.

Access Northeast built up the existing Algonquin footprint, which already touches 60% of the power generation in New England.

[It's the centers] that will grow as new proposed plants are built.

The project allows direct last-mile deliveries to the power plants to ensure greater reliability and cost benefits.

The business models that the electric utility signed pipeline capacity contracts for up to 20 years with Access Northeast, and then retained an independent capacity manager to market that capacity to generators.

Without Access Northeast, those generators are frequently unable to run their units during cold weather, when the region's existing pipeline capacity is used, primarily to heat homes and businesses.

The larger amount of new pipeline capacity is set aside to meet the needs of natural gas generators, we can depend less on more costly and higher-emitting coal and oil plants that typically run when the region's natural gas supplies run short.

We have made significant progress in the past three months.

The status of securing approval of contracts with New England electric distribution companies is on slide 12.

Following an RFP this past fall that attracted a number of bids, NSTAR Electric and Western Mass Electric filed with the Massachusetts Department of Public Utilities in December, seeking approval of contracts for pipeline and storage capacity with Access Northeast.

The two utilities asked for a decision by October 1 of this year.

National Grid's two Massachusetts electric distribution companies, Massachusetts Electric and Nantucket Electric, made a similar filing with the DPU on January 15.

Once approved by the Department of Public Utilities, these contracts will account for nearly 45% of the Access Northeast targeted capacity.

In Connecticut, a natural gas capacity RFP will be run by the state Department of Energy and Environmental Protection, or DEEP.

We expect this process to be complete later this year.

In New Hampshire, the Public Utilities Commission issued an order on January 19 in which they accepted a staff report that concluded that the PUC had sufficient authority to approve electric distribution contracts for natural gas supplies, if those contracts are shown to be in the customers' interest.

If the PUC commissioners agree with the staff that they have sufficient authority to approve such agreements, they would then determine whether the specific contracts submitted were in the customers' best interest.

In Maine, where regulators have engaged on the natural gas contracting issue for some time, bidders were given an opportunity to refresh their proposals in December.

State regulators are scheduled to reach a decision on recommended solutions by midyear.

In Rhode Island, National Grid issued an RFP in November, at the same time the Massachusetts electric distribution companies issued their RFP.

We expect National Grid to make a decision and file in the coming months with Rhode Island.

In Vermont, the State has expressed support for additional natural gas infrastructure, but its level of participation has yet to be determined.

We expect that the state processes will be concluded this fall, so that we can file our formal application with FERC before the end of 2016.

We continue to believe that Access Northeast offers an excellent near-term and long-term answer to the region's intensifying winter energy supply challenges.

Now I would like to turn the call over to Jim.

Thank you, Lee, and I would also like to thank you all for joining us this morning.

Turning to slide 14, I'll start by covering our financial and operating results for the fourth quarter and the year; our 2016 outlook and long-term EPS growth expectations through 2019; current regulatory developments, and the absence of rate case activity for the next 12 to 18 months; and I'll conclude with a brief overview of how we delivered on the commitments that were made to investors in recent years.

Let's start with the fourth quarter.

As you can see from slide 15, earnings excluding integration costs were $0.60 per share in the fourth quarter of 2015, compared with earnings of $0.72 per share in the fourth quarter of last year.

The $0.60 per share is consistent with the guidance that we gave on the third-quarter earnings call, and consistent with the updated Street estimates that have been published this year.

Electric distribution and generation earnings declined by $0.07 per share to $0.28 per share in the fourth quarter of 2015.

Higher retail electric revenue, mostly due to the December 2014 Connecticut Light & Power distribution rate decision, added about $0.05 per share to earnings.

But that impact was offset by higher property taxes and depreciation expense due to higher plant balances, and higher amortization expense due to the amortization of CL&P's deferred storm balance.

Earnings for NSTAR Electric and Public Service in New Hampshire, which do not have revenue decoupling, were lower due to milder weather.

Earnings in this segment were also lower due to a higher effective tax rate in the fourth quarter of 2015, compared with the same period last year.

On a consolidated basis, our effective tax rate was approximately 39.4% in the fourth quarter of 2015, compared with 35.4% in the fourth quarter a year ago.

The higher rate lowered consolidated earnings in the quarter, by about $0.04 per share.

As expected, transmission earnings were down $0.03 per share in the fourth quarter of 2015, due to the absence of the fourth-quarter 2014 reversal of a reserve related to FERC's review of the New England transmission ROEs.

The historically mild temperatures this past December were the primary reason for a $13.2 million, or $0.04 per share decline in our natural gas segment earnings.

Lower natural gas revenues alone cost us $0.03 per share, despite having 2% more heating customers in the fourth quarter of 2015.

Average temperatures in Boston and Hartford were 10 to 12 degrees warmer than average in December.

As a result, our firm natural gas sales were down 16% in the fourth quarter of 2015, compared with the fairly mild fourth quarter of 2014.

Parent and other improved by $0.02 per share, compared with the fourth quarter of 2014.

I'll now turn to full-year results.

Excluding integration charges, we earned $2.81 per share this year, compared with $2.65 in 2014.

2015 results were consistent with our guidance of $2.80 to $2.85 per share, and also consistent with recently updated Street estimates.

As you can see in the news release, the most significant driver of earnings growth in 2015 was higher electric revenue, which added $0.39 per share to our results, compared with last year.

The primary driver was approximately a $150 million distribution-rate increase for Connecticut Light & Power.

We also benefited from a 0.3% increase in retail electric sales.

Those higher revenues were offset in part by higher property taxes, depreciation, and the CL&P storm amortization expense in 2015.

Higher electric transmission earnings also contributed to improved year-end results.

Our transmission segment earned $0.96 per share in 2015, compared with $0.93 in 2014, benefiting in part from a higher level of investment in the business.

As a result of our robust capital program, our transmission rate base was approximately $5.2 billion at the end of 2015, compared with $4.9 billion at the end of 2014.

Those benefits were partially offset by FERC's decision last year to lower the base transmission ROE in New England to 10.57% from the previous 11.14%, and to cap our ROEs on any reliability project, regardless of previously approved incentives at 11.74%.

As we've said in the past, those changes have reduced our effective transmission ROE, including incentives, to approximately 11.5%.

Turning to our natural gas distribution business, after a very strong start, our year-end 2015 results were almost identical to those that we recorded in 2014.

For the year, due to the long fourth quarter, firm natural gas sales were down 1%, after being up 8.4% in the first quarter of 2015.

On a weather-normalized basis, sales rose 2.5% for the year.

Parent and other results were down $0.01 for the year.

Two other items worth mentioning in 2015 were the benefits of lower O&M, and the negative impact of a higher effective tax rate.

Lower non-tracked O&M added $0.08 per share to earnings in 2015.

This follows a $0.23 per share benefit in 2014, and a $0.05 per share benefit in 2013.

All together, we have reduced our O&M by about $250 million since the merger closed in 2012.

Offsetting much of that benefit was a higher effective tax rate in 2015, which lowered earnings by about $0.06 per share, as compared with the previous year.

So, in spite of the warm fourth quarter, we were still able to grow earnings for the year by $0.16 per share, or 6%, in 2015.

Turning from the financial slide to operations, as you can see on slide 16, our key reliability statistics have dramatically improved, and are record levels, as Tom mentioned.

Since 2011, the number of months between interruptions and the speed of restoration when outages do occur have both improved by about 40%.

We are well up in the top quartile of our peers, so, very proud of this accomplishment.

This closes our 2015 discussion.

Let's move on to 2016.

On slide 17, you can see we've established an earnings-per-share range of $2.90 to $3.05 this year.

The biggest year-over-year benefit will come from growth of our transmission rate base.

The second biggest positive driver will be the natural gas segment.

We expect that segment to benefit from a continued increase in natural gas heating customers; various capital initiatives, for which we have trackers; and a $15.8 million base-rate increase that was effective at NSTAR Gas on January 1 of this year.

Other drivers include lower O&M.

In the first quarter of this year, we will migrate our legacy payroll and benefits system to a single IT platform, which we've already done with our accounting and our outage management systems.

Consolidating to a single system is expected to significantly improve efficiency and lower costs in the future.

Offsetting these benefits are continued increases in depreciation, property taxes, and modestly higher interest costs, reflecting continued investment in our distribution systems.

From 2016, let's turn to the longer term and slide 18.

We estimate that we can grow earnings per share by 5% to 7% annually over the 2015 to 2019 forecast period.

This compares with our previous growth rate of 6% to 8% for the 2014 to 2018 period.

Nearly all of that change is attributable to the five-year extension of bonus appreciation for tax purposes recently passed by Congress.

We estimate that bonus depreciation alone is lowering our growth rate by approximately 1%.

Components of the 5%-to-7% growth are similar to what has driven the 7.2% annual earnings growth since our 2012 merger.

We've also noted our key assumptions about major projects, which include the completion of Northern Pass in 2019 and the construction of Access Northeast in 2018 and 2019.

Because significant Access Northeast construction is expected to continue beyond our forecast period, we anticipate that it will contribute to earnings growth in both 2020 and 2021, as well.

Electric transmission capital expenditures and rate-base growth are the primary drivers of our attractive earnings growth projection.

Turning to slide 19, you can see that capital expenditures projections are up significantly from the forecast we showed you a year ago.

To begin, I should note that our transmission capital expenditures totaled $807 million in 2015.

That's about $67 million above our projection at this time last year.

We now show nearly $5 billion of electric transmission investment from 2015 through 2019.

As we do every year, we have again identified transmission investments that we didn't have in the plan one year ago.

We've added about $800 million of new investment.

$200 million of that increase involves our previously announced increase in the Northern Pass project.

We are projecting transmission capital expenditures of $911 million in 2016, $880 million of which will be spent on reliability-related transmission projects at our four regulated electric companies.

Two of the largest initiatives, the Greater Boston and Greater Hartford projects, involve dozens of individual projects, and are described more fully in the transmission slides in our Appendix.

Those expenditures are helping to drive the significant improvements in reliability and transmission earnings growth in 2016.

You can see that we expect little capital spending on Northern Pass in 2016, but considerable expenditures in 2017 and 2018, consistent with the schedule that Lee gave you earlier.

These capital expenditures projections do not reflect our spending on the Clean Energy Connect project Lee discussed earlier, which we expect to contribute to earnings growth from 2018 to 2021.

We continue to work on both Clean Energy Connect and other potential projects that we expect to be approved.

As a result, the arrow on the slides shows that we do not expect a significant decline in transmission spending in 2019, but we have not included all of the potential projects that are likely to be built that year.

Because we are in a competitive bidding process, we are not providing a total cost of the Clean Energy Connect project, or a year-by-year estimate for capital expenditures.

We hope to provide that to you, should the project be selected.

Let's turn to slide 20.

On the left-hand side, this slide shows our capital program, excluding both Access Northeast and Clean Energy Connect.

From 2016 through 2019, we expect to invest $9.2 billion in New England's energy infrastructure, including $3.9 billion in transmission that I mentioned earlier.

You can see that electric and natural gas distribution capital total about $1.2 billion every year during that period.

A slide in the Appendix shows that investments in our natural gas delivery system will comprise a rising percentage of that investment.

On the right-hand side, we have estimated the pace of our $1.2 billion projected investment in the Access Northeast project, which costs a total of $3 billion.

Our FERC application indicates that elements of Access Northeast will be phased into service between late 2018 and 2021.

On slide 21, we illustrate how the composition of our rate base is expected to change by the end of 2019.

About $2.5 billion of the $3.6 billion of rate-base growth over the next four years is expected to come from electric transmission.

By the end of 2019, we expect that electric transmission will comprise 42% of our total rate base, and if our Access Northeast and Clean Energy Connect investments were included, it puts us at nearly 50% FERC-regulated company by the end of 2019.

We believe that this rising percentage of FERC investments will result in an increasing ROE for Eversource Energy, as a whole.

Slide 22 shows various initiatives that we expect to continue beyond our current four-year forecast.

As I said earlier, we expect significant expenditures on Access Northeast, Clean Energy Connect, and other projects we are working on.

We also expect continued work on modernizing the electric grid in Massachusetts, assuming our $430 million five-year plan and capital tracker are approved by the state regulators, we expect, later this year.

A lot of initiatives are primarily tied to growing our natural gas distribution business.

Turning to slide 23, you can see despite declining oil prices, we added 11,415 new natural gas customers in 2015.

This is about 7.5% ahead of 2014 and 4% ahead of our target for the year.

The slide shows that we expect new heating customer growth to continue to accelerate over our forecast period, and eventually reach about 16,000 per year, significantly aided by legislatively endorsed initiatives in both Connecticut and Massachusetts.

In 2016, we're projecting approximately 12,500 new natural gas heating customers, and Tom mentioned that, one month into the year, we're on plan.

Schedule 24 -- slide 24 reviews two important regulatory items that are currently pending.

Hearings on the divestiture of our New Hampshire generation fleet were completed this week, and we expect a decision within the next two months.

Last week, a settlement was filed with certain advisory staff at the New Hampshire PUC, who had earlier supported a delay to the sale.

They now support near-term divestiture.

Should the New Hampshire PUC authorize the divestiture, we expect the sale process and securitization to be completed later this year and early next year.

As a reminder, we expect full recovery of approximately $700 million invested in New Hampshire generation by early 2017.

In December, the FERC administrative law judge handling the second and third New England transmission ROE complaints requested some additional briefing on an aspect of the second complaint.

So, an initial recommendation by that ALJ was delayed, from December 2015 to the end of March 2016.

Because of that three-month delay by the ALJ, we now expect to receive a decision from FERC on the two complaints in either late 2016 or early 2017.

As you can see on slide 25, we have no general rate cases currently pending for any of our six regulated distribution utilities.

And, while we do expect rate-case activity next year, we expect that any decisions would not impact our financial results until the end of 2017 or early 2018.

So, we have very good visibility into our distribution company results for the next two years.

Turning to this year's financing calendar, 2016 is likely to be similar to last year.

One benefit of bonus depreciation, of course, is that it lowers our cash tax obligation.

In 2016, we will receive an estimated $250 million to $300 million in refunds from taxes paid in 2015.

Additionally, we expect our cash tax liability for 2016 to be lowered by approximately $300 million as well.

In 2017, bonus depreciation is estimated to lower our cash tax obligation by another $300 million.

Slide 26 shows the current distribution of S&P's electric utility credit ratings, with Eversource as the only A-rated parent company, as a result of our upgrade last year.

We've also noted on the slide several positive outlooks on other -- our subsidiaries, at both Fitch and Moody's.

Slide 27 shows the relative price performance of Eversource's shares versus the S&P 500 and the UTY, since our merger was announced more than four years ago.

We're very proud of our total shareholder return, as well as our strong credit ratings.

We strongly believe that financial strength and attractive shareholder returns can certainly both coexist -- and do -- at Eversource.

Slide 28 sums up what we have delivered to customers, policy makers, and investors over the past four years.

We committed that we would exceed industry earnings per share and dividend growth rates, and we delivered with growth rates that are 2 times the industry average for three years.

We targeted O&M reductions of 3% to 4%, and we achieved 5% per year for three years on average.

We said we would maintain a strong financial condition.

We've done better than maintain -- three upgrades since the merger announcement has us with the only A credit in our industry.

We committed to top-tier service in reliability -- a 40% improvement in reliability has us now consistently in the top quartile of our peers.

We committed to grow and leverage our transmission and gas business -- this morning, we have discussed the great portfolio of projects that will continue that great growth.

And, finally, advancing energy policy in the region -- our Access Northeast project, Northern Pass, and Clean Energy Connect are game changers, cost effectively advancing the region's carbon-reduction agenda effectively.

Eversource continues to be a very attractive offering for investors, and we're confident it will continue to be in the years ahead.

Now, I'll turn the call back to Jeff.

Thank you, Jim.

I'm going to turn the call back to John just to remind you how to enter questions.

John?

(Operator Instructions)

Thank you, John.

First question this morning is from Greg Gordon from Evercore ISI.

Good morning, Greg.

So this whole bonus depreciation thing is a high-class problem, obviously significantly increases the cash flow, even though it's a bit dilutive to rate-base growth.

I'm just wondering, you said that the vast majority of the reduction in the growth rate is due to bonus, and yet you've also significantly increased your capital expenditure budget.

So algebraically, that means that the overall growth rate is more than 1% lower, before the offset of the higher capital plan.

So is bonus in fact the sole driver of that, or are there other factors?

I would say that bonus is the sole driver of it.

The numbers that I mentioned, Greg, $300 million a year, obviously the pancaking impact of that when you look at 2015, 2016, 2017 and beyond, has a significant impact on our cumulative deferred income taxes and we're obviously a purely regulated T&D company, so it does impact our ability to earn.

I've seen a number of estimates out there where companies have -- analysts have estimated that it's about a 1% increase on a -- decrease on a Company like Eversource.

I would tell you this, that as you well know, we have a long track record, Tom and I, 20 years, of delivering on guidance, either meeting or exceeding it.

The other thing that I would mention is we tend to provide data to the Street, forecasted data, capital expenditure data, that ties out to the dollar to projects that we have in the queue.

We have obviously updated the forecast for the projects that we have, and the impact has been 5% to 7% growth rate is a better guidance for Wall Street, a more credible guidance than the 6% to 8% that we had previously.

That being said, I will tell you a year ago, we didn't provide capital expenditure numbers for Access Northeast, and look how far along that project has come.

Three months ago at our third-quarter call, we didn't provide any guidance, Clean Energy Connect wasn't even mentioned as a project, and we now have that before the regulator to be approved.

We tend to find projects going forward.

We don't put them into our plan until they are real.

I think we have a very credible 5% to 7%, with some upside going forward.

I agree.

One last question.

Are you electing to take bonus on Northern Pass, or are you going to choose not to take bonus on that particular project?

We have customers paying for it, and it's largely a FERC-type of formula and cost recovery mechanism.

We would expect the benefits of bonus depreciation to be shared with customers.

Okay.

Thank you.

Have a good morning.

Thanks, Greg.

The next question is from Dan Eggers from Credit Suisse.

Good morning, Dan.

Just following up on Greg's question on the bonus depreciation side.

You think, in 2016 and 2017, you'll bring in about $900 million of bonus cash, and then you've got the proceeds from the New Hampshire sale or securitization coming in, in probably early 2017.

How are you thinking about using that, the incremental pile of cash relative to old expectations, where you didn't need equity without having that cash come in?

Well, we still don't need equity, and that's obviously cash that can be redeployed towards projects.

That's capital, that's shareholder capital.

If it turns out that we can't redeploy it towards new projects, we certainly would consider giving it back to shareholders in the form of increased dividends or more effectively through a share buyback, if need be.

I guess, how are you accounting for that extra cash in the growth rate?

Are you assuming that it accumulates on the balance sheet, or is there some redeployment assumption in the underlying growth rate?

In the underlying growth rate, we actually are very, very cash strong, and so, again, absent another project to invest it in, we assume a share buyback would be the best application of it.

Okay.

And I guess, Tom, the merger's been very successful for you.

You've executed on what you had laid out when you did the deal, had a very convenient name change along the way.

How do you think about M&A at this juncture, and given your success thus far, is this something you could take on the road again?

We have a very strong Company.

We are also in a very exciting place in New England.

You get a sense of what we're telling you, and you don't have a sense on our to-do list.

But there is a lot happening in New England, and it's pretty exciting, and that's why, as Jim said, we'll have fun with capital allocations.

We hope there are more and more projects to deploy our excess capital in, but if not, we're very flexible, and we're very shareholder-oriented.

On the M&A side, I'll just say that we've always been big believers that consolidation in our industry makes sense.

However, we have also been very selective with respect to what makes sense for our shareholders and for our customers, and we do believe that, and I think we proved it over the years, that you can actually spend less money operating a business and provide world-class service and improve service along the way, by using size and scale and technology.

But things are pretty overheated right now.

We do believe that you go through ebbs and flows, there will be opportunities.

Right now, we're focused order executing the plan we put in front of you.

Got it.

Thank you.

Thanks, Dan.

Our next question is from Julien Dumoulin-Smith from UBS.

Good morning, Julien.

I wanted to dig in a little bit more on the Clean Energy Connect.

Admittedly, I know it might be challenging, but first, just to get a sense, is this connected to firm renewables back in New York?

Could you talk about the project a little bit, just in terms of how we should think about it?

Then on the financials, if you can elaborate, is it accruing AFUDC whatever construct you have devised with your partners?

And in terms of return, would it be fair to continue to say this is a FERC-like return on a typical equity ratio as we think about at least preliminarily the $400 million you've contemplated?

Julien, this is Lee Olivier.

In regards to the project itself, it really is designed around getting existing run of the river renewable plans that are in place in New York and building new wind, and as you can see from our partners, from e-patroller, EDP, we would build new wind.

And getting that combined power, so you can firm up the wind with the hydropower, such that when you have a transmission line going into New England, you have 100% deliverability into the region, and you have very, very high capacity factors of utilization across that line to the extent of 80% to 90% utilization.

It would accrue AFUDC, and it would garner FERC-like returns.

Got it.

All right.

Excellent.

And then just turning over to the conversions, the oil conversion side of the equation, I would just be curious, you talked about continued strength, particularly on the back of your reasonable winter thus far, moderate, shall we say, but what's the normalized trend of late?

I would be curious, given how low oil prices are of late.

Is there something to be concerned about as we think about a more normalized weather pattern for the next 2016-2017 winter, that we should be thinking about a slowdown at all?

No, in the forecast we provided on slide 23, we continue to be comfortable with.

If you look at each of the years, 2013, 2014, and 2015, we exceeded the targets that we had provided.

Even given the dramatic reduction in oil prices that existed for most of 2015, we have great opportunity, primarily because of the lack of penetration down in Connecticut.

It's significantly underpenetrated, and we feel pretty good about our target for 2016 and achieving it as well.

So perhaps said differently, the penetration level is such that there is still clear economic benefits for customers to continue to switch at the same pace they have?

Or at least you feel confident in the ability to garner the same conversion pace that you have historically?

I think the payback for conversion is more challenging than it was a year or two ago.

But we've got some more aggressive marketing and the carbon benefits of gas versus oil are compelling to customers, as well.

I'm not going to suggest that it's not more challenging than it was a year or two ago, but we still feel pretty good about our ability to execute.

It's interesting.

If anything is new construction anywhere in our territory, they want natural gas for heating.

It actually adds value to the house.

There are studies that have shown that houses are selling for $10,000 or $20,000 more if, instead of having an old oil tank on your property, you have a pipe that -- without trucks pulling up and down your street.

But we're seeing lots of communities that are actually encouraging us to come in and help them reduce their carbon footprint.

We call it the three Ps.

They don't require us to make permit fees.

They don't require us to have police details.

And what's -- paving.

They don't make us pave curb to curb.

Typically when you go in and cut a street to put a pipe down in for a neighborhood, they want you to pave curb to curb.

They will say, hey, we'll let you patch that cut, and therefore, we do reduce the price to come in and bring this gas to our neighbors.

So interestingly, the demand is still there, but as you say, the payback for our customer is quite different, and therefore you have to find different ways to turn it into a monthly payment rather than a big lump sum.

And then last, a quick clarification, the 5% to 7%, the Clean Energy Connect, is it in there?

How do you think about it?

It is in there, but again, the CapEx spend there is $18 million to $21 million.

So it doesn't move the dial much one way or another.

It's a small piece of the financials out in 2018-2019.

Fair enough.

Thank you.

Thanks, Julian.

Next question is from Travis Miller from Morningstar.

Good morning, Travis.

Good morning.

Thank you.

I was wondering, as you talk more about these renewables, look three to five years out, obviously you have a lot of transmission spend opportunity.

I was wondering if you could elaborate on potential upside for the distribution side, the electric distribution side?

Is there upside in your plan?

Is there additional, in terms of integrating all of that renewable energy that will come in through the transmission projects?

Sure, Travis, this is Jim.

We mention that we spend about $1.2 billion a year on the distribution system that's gas and electric.

But in particular, we have a slide that references this grid modernization plan.

It's $430 million of spending over the next five years.

Included in there is advanced sensing technology, and next generation fault, circuit indications, and those sorts of things.

But a good part of the spend there has to do with making it easier for distributed resources to be tapped into the system and provided for.

So that's a filing that's before the regulator in Massachusetts currently, and we expect the plan to be approved later this year.

Okay.

That's all I had.

Thank you.

Thanks, Travis.

Next question is from Shahriar Pourreza from Guggenheim.

Good morning, Shahriar.

Just a real quick question on the growth.

So you have the regulatory mechanisms at the utilities and you assume Northern Pass and Access Northeast are on schedule.

So what's the driver to get you to the top end or exceed your updated growth trajectory, or how should we think about the bottom or top end of that range?

Well, I would say, Shah, is that obviously if all the projects go forward as planned, we would be higher in that 5% to 7% range.

But I do think that we have some flexibility in that range, such that if one of the projects didn't go forward, I think we would still be able to achieve the lower end of that range.

Okay, got it.

So if your projects are on schedule, you can essentially hit the midpoint of your old range?

Or beyond.

Excellent.

Thanks.

Thanks, Shah.

Next question is from Michael Lapides from Goldman.

Good morning, Mike.

Couple of housekeeping-related questions.

First of all, in 2016 guidance, what are you assuming for O&M cost management, on controllable O&M?

Michael, this is Jim.

We're basically providing estimates of 2% to 3% long-term and there will be some variability year to year.

We're not giving a spot-specific number for 2016, but you've seen our performance to date, and you can assume that 2% to 3%, you can take to the bank.

Well, I mean, actually you've done a really good job of just completely blowing right past that 2% to 3% a year in the first couple years post-merger.

Just trying to get my arms around the, what would drive a fundamental slowdown in the O&M cost savings, or are you just being a little bit on the conservative side about your ability to manage cost structure, post-merger?

We've been giving guidance historically of 3% to 4% and we've exceeded it.

2% to 3% I guess reflects a little bit of a slowdown, but we do see ample opportunity.

Eventually you go from merger synergies, which I think we've largely achieved, into achieving savings, just by good cost discipline across the organization, and that's the phase that we're in now.

Tom and I mentioned some of the IT system conversions that are taking place currently that will fuel savings going forward.

In our operations area, standardization that takes place is assured to provide us some additional savings.

We feel good about it, but obviously, the 2% to 3% is an indication that it has tempered a little bit from what we got the first few years.

Got it.

And can you frame for us a little bit just the difference in the second and third FERC ROE complaints, relative to the one that already lowered your ROE?

And if so, what's the -- if complainants get what they ask for, or if staff gets what they are kind of nodding towards, what the impact on earnings power and the growth rate would be?

The filings that were made, the initial briefs that were filed and updated at FERC, the position of the New England transmission owners is that if you do the math, similar to what was done by FERC in complaint number one, that the ROE would be 10.24% and if you did the math the same way for complaint number three, it would be 10.9%.

If you average those two, you get to where we are currently, 10.57%.

So we would expect and hope that FERC would realize that there hasn't been a dramatic change in what they approved over the year ago, in terms of the base ROE.

The same logic applies on the cap as well.

The 11.74% sits well within what the math would show from applying the new methodology at FERC to the time frames that were considered for complaint two or three.

Obviously, the series of conflicting testimony, I guess, from the consumer advocates groups and from FERC staff, that would have slightly lower numbers.

We feel pretty good about our prospects in terms of the case that were presented.

Thanks, guys.

Much appreciated.

Congrats on a good year.

Thanks, Michael.

Next question is from Praful Mehta from Citi.

Good morning, Praful.

I just had two quick questions.

One was on Northern Pass.

And just want to understand if there were delays in the Northern Pass CapEx plan and implementation, are there other levers to fill the hole in terms of EPS?

Or is there going to be an impact to EPS as you see it today?

This is Jim, Praful.

As I mentioned, we come up with projects that we don't even have on the drawing board.

We're looking at other projects currently.

You're asking me if Northern Pass, the $1.6 billion was significantly delayed, what would we backfill it with?

I would assume by the time we get out to 2017, 2018 and 2019, there will be new projects, but right now they have not been defined or we haven't reached the stage where we would include them in our plan.

Fair enough.

Got it.

Secondly, in terms of capital allocation, you've talked about the excess cash that you have, bonus depreciation and one of the options could be share buybacks.

From a timing perspective, how do you see that decision playing out?

Do you wait and see if you have new projects in 2016, 2017, and if you don't, and if you have excess cash, do you do the buyback?

I'm trying to figure out how does that sequence of events go, and when does that decision take place to actually do buybacks?

We will look at that on a year-to-year basis.

Obviously, we have not announced a share buyback.

We don't anticipate one in 2016.

We think we have potential application of this excess cash in years beyond that, but if we don't, it's clearly capital that deservedly would go back to shareholders, and we would consider a share buyback.

It's basically a year-to-year decision.

Thank you.

Thank you.

Next question is from Steve Fleishman from Wolfe.

Good morning, Steve.

Just briefly, in the context of the bonus depreciation and the plan that you're giving us, maybe you could just talk about how the balance sheet or cash flow metrics look under this plan, as it is, versus maybe you had before to fill in the whole picture?

Well, we certainly think that the cash flow numbers improved, given the bonus depreciation, the lack of tax payments that need to be made.

We fully expect to maintain the strong single-A credit that we have achieved to date.

So I think the credit metrics would reflect that.

Okay.

Thank you.

Thanks, Steve.

We don't have any more questions this morning.

So we want to thank you very much for joining us.

If you have any follow-up questions, please give us a call.

Thanks, and enjoy the rest of the winter.

We'll see you at a couple of the conferences.

Thank you.

Ladies and gentlemen, that concludes today's conference.

Thank you for participating.

You may now disconnect.