康涅狄格電力 (ES) 2017 Q4 法說會逐字稿

Welcome to the Eversource Energy Fourth Quarter 2017 and Year-End Results Conference Call.

My name is Vanessa, and I will be your operator for today's call.

(Operator Instructions) Please note that this conference is being recorded.

And I will now turn the call over to Mr. Jeffrey Kotkin.

You may begin, sir.

Thank you, Vanessa.

Good morning, and thank you for joining us.

During this call, we'll be referencing slides that we posted last night on our website.

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

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 the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995.

These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections.

Some of these factors are set forth in the news release issued yesterday.

Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2016, and the 10-Q for the 3 months ended September 30, 2017.

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 and in our most recent 10-K.

Turning to Slide 2. Speaking today will be Jim Judge, our President, Chairman and CEO; Lee Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development; and Phil Lembo, our Executive Vice President and CFO.

Also joining us today are Jay Buth, our VP and Controller; John Moreira, our VP of Financial Planning and Analysis.

Now I will turn to Slide 4, and turn over the call to Jim.

Thank you, Jeff.

I want to thank everyone, who's joining us this morning for our recap of the year that we just completed and a comprehensive look at our opportunities and financial outlook for the next 4 years.

To start, I want to congratulate our 8,000 employees for the great progress we made over the past year in achieving our vision of being recognized as the best utility in the country and as a catalyst of clean energy development in New England.

Our region is mandating a 75% to 80% reduction in carbon emissions by the year 2050.

And we plan to play a central role in helping New England reach its targets.

All the coal, oil and nuclear plants continue to retire, only to be replaced by renewables and natural gas.

Two large and economic new sources of renewable energy are hydroelectric power in Québec and offshore wind southeast of Massachusetts.

Through Northern Pass and Bay State Wind, we expect to be deeply involved and accessing both.

And Hydro-Québec and Ørsted are great partners.

We continue to believe that Northern Pass is uniquely designed to significantly lower the region's greenhouse gas emissions, reduce energy costs and reduce our growing and increasingly ominous dependence on natural gas for power generation.

We were surprised and disappointed, and I'm going to say, humbled, by the recent decision from the New Hampshire Site Evaluation Committee rejecting the project.

Clearly, we have not fully addressed all the major concerns in New Hampshire yet.

We're expecting the process to allow us to address what were legitimate concerns raised during the proceedings.

If allowed rehearing, we expect there may be an opportunity to address those concerns.

In a couple of minutes, we will discuss the steps we are taking to move the project ahead.

At the same time, we continue to lead the way in bringing other cost-effective energy solutions to customers in the region.

We have completed the sale of our fossil plants, are well underway in the construction of 62 megawatts of additional rate-based solar, are beginning to build our first two utility-scale battery storage facilities, are developing the infrastructure needed to expand access to electric vehicle charging stations in the region, and we are continuing to run the nation's #1 ranked energy efficiency programs.

We also acquired Aquarion, adding a long-term opportunity to move into the water delivery business.

Rates are fully decoupled at our FERC-regulated transmission business.

And on the distribution side, we now have full revenue decoupling for more than 3 million of our 4 million customers.

This allows both our customers and our shareholders to benefit from the implementation of our aggressive energy efficiency programs and not be hurt by them financially.

Moving from our strategic initiatives.

We also achieved significant operational, financial and regulatory successes over the past 12 months.

We are working with regulators in each of the states that we serve to identify the investments needed to modernize the electric grid and improve its capabilities and resiliency.

We have doubled the pace at which we are replacing older natural gas pipelines and are accelerating Aquarion's water main replacement program.

We also have a group of new commissioners at FERC, who clearly favor infrastructure enhancement.

We had a record-setting electric reliability and employee safety performance, our best year ever on both measures, and are well within the top quartile of our industry peers.

On the regulatory side, we achieved constructive outcomes to NSTAR's first fully litigated Massachusetts distribution rate case in over 30 years and recently negotiated and filed with regulators in Connecticut the first settlement of our Connecticut Light & Power distribution rate case since 1986.

Turning to Slide 5. We reported GAAP earnings of $3.11 despite a very mild summer.

We also reiterate our 5% to 7% EPS growth, now using the 2017 earnings level as our base.

We have both the investment opportunities and the balance sheet capacity to deliver on our outlook.

Slide 6 shows that over 1-year, 3-year, 5-year and 10-year periods, our shareholders have benefited from our strong execution of our business strategy.

Our total return has consistently exceeded our peer averages.

In 2017, Eversource's return to shareholders was 60% higher than our EEI peers, and over 10 years, nearly 2x our peer's performance.

Part of that strong total return profile has been a rising dividend.

We are committed to raising our dividend at a pace that is above the industry average and consistent with our earnings growth.

As you can see on Slide 7, we announced 6.3% increase earlier this month.

In December, we were upgraded by S&P to A+, resulting in a two-notch difference between us and the second-highest-rated electric utility.

We have the financial strength and the knowledge and skills to help our region meet some very significant energy-related challenges.

Turning to Slide 8, the cold snap in late December and early January reminded us just how fragile New England's winter time energy supply situation is today, and how it's likely to worsen due to additional plant retirements before it improves.

During that period, New England's natural gas prices were the highest, not just in the U.S., but the highest in the world.

While just 200 miles to the east of us, natural gas prices were the lowest in the world.

This differential cost our region approximately $500 million over less than a two-week period.

As Lee will discuss in more detail, the issue is not just economic.

Running the region's oil, coal and diesel fleet flat out for two weeks added over 1 million tons of carbon emissions, highlighting the critical need for additional wintertime natural gas capacity in New England.

These challenges require a solution, and we're well positioned to lead in this effort.

Before closing my remarks, I want to stress that each day, our employees are in the front lines, making us a trusted partner in our efforts to reduce energy costs, providing a top-tier level of service and promoting our region's energy policies.

There's no finer group in the industry, and they're the primary reason I'm so optimistic about the company's future.

Now I'll turn over the call to Lee.

Okay.

Thanks, Jim.

I'll provide you with an update on major projects, expand on Jim's comments on the New England winter supply situation and then turn the call over to Phil.

I'll start with Northern Pass.

Following our November earnings call, we received a string of good news about the project with various federal and state approvals, listed on Slide 10.

In late January, the combination of Northern Pass transmission and Hydro-Québec's all-hydro energy offering won the entire Massachusetts Clean Energy RFP, although over more than 40 other clean energy projects of various scales and technology.

The RFP sought nearly 9.5 billion kilowatt hours a year of clean energy for up to 20 years, and our bid was the sole winner.

Clearly, NPT is the best clean energy solution for the region.

However, on February 1, we experienced a setback.

The NHSEC had commenced deliberations on January 30 and then determined that Northern Pass possessed the financial, technical and managerial capability to construct, operate and maintain the project.

And the SEC members began discussing criteria known as orderly development.

They noted the benefits Northern Pass would have in multiple areas, including promoting economic development, job growth and increased property tax revenues.

But members indicated they were concerned about the other items, such as tourism, property values and the impact on municipal development plans.

Without discussion of potential conditions that could've been imposed to address those concerns, the SEC ended the deliberations then voted unanimously to reject the project.

Left undiscussed were key topics, such as whether the Northern Pass would serve the public interest, whether it would have an unreasonable adverse effect on aesthetics, historic sites, air and water quality and the natural environment and public health and safety.

As Jim said, we were deeply disappointed by the committee's decision, we have a compelling case about the key benefits of the project, including more than $3 billion of economic benefits to the state over the life of the project; the elimination of 3 million tons of carbon emissions in New England each year - that's equivalent to taking about 670,000 cars off the road; the creation of 2,600 jobs in New Hampshire during construction; the $600 million of annual regional cost energy savings, including $62 million a year in New Hampshire; the additional $30 million in property tax revenues in New Hampshire annually; and an average increase in New Hampshire's GDP of $162 million a year; and the commitment to fund $200 million over 20 years for New Hampshire communities, tourism, clean energy and economic development.

We will ask the New Hampshire SEC to reconsider its decision shortly.

If the committee reconsiders its decision and votes to approve the project, we expect to begin construction this year.

The SEC decision has been reviewed by evaluators in the Massachusetts Clean Energy RFP.

On February 14, the electric distribution companies with the Massachusetts Department of Energy Resources and the RFP's independent evaluator, notified Northern Pass that they will continue negotiations with the project through March 27, 2018.

But in parallel, they'll negotiate with a runner-up project.

Hydro-Québec leadership continues to support the project as by far the most advanced initiative to boost the sale of Québec hydroelectric power into New England.

We continue to work to advance the project forward, and we will update you as we move ahead.

From Northern Pass, I want to move to Slide 11 and Bay State Wind, our 50-50 partnership with Ørsted, the world leader in development of offshore wind.

Bay State Wind seeks to construct and operate at least 2,000 megawatts of offshore wind facilities, 15 to 25 miles south of Martha's Vineyard.

Our site is very well situated to serve four states that are currently pursuing long-term contracts for renewable energy, including offshore wind.

Turning to Slide 12.

In December, we submitted 2 bids into the RFP overseen by the Massachusetts Department of Energy Resources and the state's three electric utilities.

The RFP required all three bidders to submit the proposal for 400 megawatts of offshore wind, but also provided an option to submit a second bid for as little as 200 megawatts and for as much as 800 megawatts.

Bay State Wind submitted highly compelling bids for both 400 megawatts and 800 megawatts.

The two other bidders submitted proposals for offshore wind generation.

And the bid evaluators are due to make their selection by April 23 and to submit contracts to the Massachusetts Department of Public Utilities by the end of July.

We believe that our Bay State Wind partnership, the combination of the world leader in offshore wind development with New England's leading transmission developer, will provide evaluators with two very attractive options to consider.

If we are chosen, we would initiate the federal and state permitting processes in late 2018 and expect to be in service in the early 2020s.

This RFP is just the first of multiple offshore wind RFPs in which we expect Bay State Wind to bid.

Massachusetts is required to contract for 1,600 megawatts of offshore wind by 2027, but it is seeking no more than 800 megawatts in this RFP.

Three weeks ago, Connecticut issued an RFP for certain Class 1 renewable resources, including nearly 200 megawatts of offshore wind.

Rhode Island has indicated an interest in contracting for up to 1,000 megawatts of additional renewables by 2020 and announced the plan for a 400 megawatt RFP later this year.

Finally, New York has indicated that it'll seek proposals for 800 megawatts of offshore wind over the next two years.

Bay State Wind's favorable geographic location would allow it to bid into all of these RFPs.

But due to competitive reasons, we have not provided investors with specific levels of expected investment in Bay State Wind at this time.

Offshore wind is particularly favorable in New England during the winter period, when wind speeds along the Atlantic coast are higher and more consistent, and when the region has the greatest challenges for cost-competitive fuel supplies.

Furthermore, Bay State Wind's facilities can be interconnected into our 345-kV AC system with minimal upgrades onshore.

While our offshore wind facilities would improve the region's fuel diversity, particularly in the winter, they are not nearly enough to offset the need for additional natural gas pipeline capacity.

Moving to Slide 13, Jim earlier reviewed some of the cost and environmental impacts resulting from the late December and early January cold snap.

The extended cold snap was similar to the Polar Vortex in 2013 and '14.

Natural gas prices soared as available supplies were directed not to power plants, but to heating homes and businesses that had paid for firm capacity.

Without adequate supplies of natural gas, New England grid operators turned to older, inefficient, costly and high-carbon-emitting oil and coal plants to keep the region's lights on.

During the cold snap, as little as 2,500 megawatts of the region's 18,000 megawatts of natural gas generation was available to run on natural gas, a situation that drove the increased oil and coal usage.

The intensive oil consumption meant that many of the region's oil units were within two days of running out of oil by the time that the cold weather snap broke.

Massachusetts Energy Secretary, Matt Beaton, described the impact on air emissions as a disaster.

Slide 14 illustrates the tremendous reduction of greenhouse gas emissions in New England that they have achieved since 2001, largely because of the switchover from oil and coal to natural gas.

There's no question additional access to natural gas in New England is critical to ensure reliability, lower customer costs and to meet the region's greenhouse gas reduction goals.

We continue to discuss the supply situation with various stakeholders in New England and Washington to identify a path that will allow a brownfield project moving forward.

You know that ISO New England is increasingly concerned about this wintertime vulnerability, which will be further challenged when Pilgrim's 700 megawatts of nuclear generation facilities retires next year.

An important fuel security report that ISO New England published last month indicated that no later than the winter of 2024 and 2025, New England would likely require load shedding six days in winter for a total of 14 hours.

And that was a reference case.

In a severe case, that load shedding would become more frequent.

In the 2018 Regional Electricity Outlook published last week, ISO New England Chairman and CEO wrote, and I quote, "In the coming years, as more oil and coal and nuclear plants leave the system, keeping the lights on in New England will become an even more tenuous proposition." The new group of Massachusetts business and civic leaders from across the Commonwealth, the Mass Coalition for Sustainable Energy, wrote Governor Baker and the state legislature leadership on February 7, expressing deep concern about, and I quote, "The existing and rapidly increasing shortfall of reliable and affordable energy in New England." They noted, again I quote, "By boosting our supply of natural gas, we can stabilize energy prices, reduce cost to rate payers, attract jobs and new businesses, while also speeding our transition to renewable energy and advancing our position as a climate change leader."

We firmly believe that periodic load shedding during bitter winter days will be a terrible development for the region.

And we'll continue to develop strategies that will allow for pipeline expansion to proceed and plan to update you later this year on that progress.

Now I'm going to turn the call over to Phil.

Thank you, Lee.

And today, I'll cover our fourth quarter and full year 2017 financial results, our new four-year capital expenditure and rate base growth forecast, the status of our key regulatory dockets and discuss the impact of tax reform.

I'll start with our fourth quarter results on Slide 16.

Earnings were $0.75 per share in the fourth quarter of '17 compared with $0.72 per share in the fourth quarter of '16.

The primary driver for the increase was improved electric distribution results, where earnings were $0.33 per share compared with $0.26 per share for the same period in 2016.

The earnings increase was due primarily to a lower effective tax rate, lower non-tracked operations and maintenance cost and modest revenue growth.

And these are partially offset by higher depreciation and property tax expense.

Our electric transmission segment earned a total of $0.32 per share in the fourth quarter of '17 compared with $0.33 in the fourth quarter of '16.

The decline is due to a $0.05 gain we recorded in 2016 as a result of FERC's approval of a settlement, allowing us to recover certain merger costs through transmission rates.

There was no such gain in the fourth quarter of 2017.

We did benefit also from higher transmission rate base due to continued investment in our infrastructure.

Transmission capital expenditures totaled $932 million in 2017 compared to $897 million in '16 and $807 million in 2015.

Earnings at our natural gas distribution segment totaled $0.08 per share in both the fourth quarter of 2017 and '16.

A 4.7% increase in the fourth quarter sales in '17 was offset by higher depreciation, O&M and property tax expense.

At Eversource parent and other, we earned $0.02 per share in the fourth quarter of '17 compared with $0.05 per share in the fourth quarter of '16.

The decline was primarily due to a $0.05 benefit in the fourth quarter of '16 relating to tax deductions on certain executive comp payments.

Turning from the fourth quarter to full year results.

We earned $3.11 per share in 2017 compared with $2.96 per share in 2016.

Our electric distribution business earned $1.57 per share in 2017 compared with $1.46 per share in 2016.

The improvement was primarily due to a lower effective tax rate and lower operations and maintenance costs, partially offset by higher depreciation and property tax expense.

Our transmission segment earned $1.23 per share in 2017 compared to $1.16 in the prior year.

The improvement was due to an increased level of investment, partially offset by the absence of the merger cost recovery item I mentioned earlier.

Our natural gas distribution segment earned $0.23 per share in 2017 compared with earnings of $0.24 in 2016.

The slight decline was due to higher depreciation, O&M costs and property taxes and nearly offset by a 3% increase in sales.

The Eversource parent and other earned $0.08 per share in 2017 compared with $0.10 in 2016.

The decline was primarily due to the 2016 tax benefit I mentioned previously.

Turning from 2017, let's take a look at 2018 and our guidance.

As you can see on Slide 17, we project earnings this year between $3.20 and $3.30 per share.

Positive year-over-year drivers include investments in our electric transmission segment, where we expect to invest approximately $900 million again this year on reliability projects; and the addition of Aquarion Water, which we closed near the very end of 2017.

We also expect to benefit from the improvement of results in our Western Massachusetts operations, which had been underearning in recent years, but implemented a modest rate increase at the beginning of this month.

I'll talk about our rate proceeding in a minute.

Partially offsetting these benefits are expected increases in property tax and depreciation expense and the absence of PSNH generation earnings.

As Jim talked about, we divested the thermal business early in 2018.

We completed the sale in January and expect to complete the sale of the hydro plants in the coming months and the securitization of remaining stranded costs in the spring.

We expect total operations and maintenance costs to decline by about 1% to 2% in 2018.

From 2018 guidance, turn to Slide 18 and our new four-year capital expenditure and rate-base growth forecast.

As you can see, we expect to invest nearly $11 billion in our infrastructure over that four-year period.

It is significantly higher than the $9.6 billion four-year plan we showed you last year.

I'll discuss some of the major contributors to that increase.

First is our new water segment as a result of our Aquarion transaction.

We project approximately $435 million of capital expenditures at Aquarion over the next 4 years.

This compares to approximately $300 million of capital expenditures at Aquarion over the previous four-year period.

The increase is due primarily to accelerated water main replacements, and the major project to increase our ability to move water from the Bridgeport, Connecticut area to address the growing needs in the Stamford/Greenwich area of the state.

In the natural gas segment, we now project more than $1.6 billion of capital spending in our new four-year forecast compared with $1.45 billion in the previous forecast.

Much of this investment is related to more rapid replacement of our older cast iron, bare steel, and in other mains and services.

As a result of constructive regulatory frameworks, we are now able to complete replacement of these mains and services in 15 years in Connecticut and 22 years in Massachusetts where the system has a larger inventory of pipes to be replaced.

These needed investments will be recovered largely through capital tracker mechanisms.

In both states, we've doubled the rate of replacement over the past five years, an investment that will help us lower our O&M costs by reducing the number of repairs and also reduce methane emissions, a measure which is followed closely by us and by the growing number of ESG investors we have.

Within the transmission segment, we split our reliability projects at our CL&P, NSTAR Electric and PSNH from Northern Pass.

Reliability transmission spending is projected at $2.6 billion through 2021, an increase of nearly $680 million in the years 2018 through 2020, plus another $525 million in 2021.

Since last year's forecast, we have increased transmission CapEx at the T&D utilities by approximately $141 million in 2018, $260 million in 2019, and $280 million in 2020.

These increases reflect projects that have already completed their required regulatory reviews or currently already going through the necessary processes.

Turning to Slide 19, you can see that we ended 2017 with about $16.7 billion of rate base, and this reflects the addition of Aquarion and the removal of the New Hampshire generation.

So we added about $1 billion of rate base in 2017 in infrastructure.

The $16.7 billion total includes about $8 billion of electric distribution rate base; $6 billion of electric transmission rate base, that's at the three T&D utilities; plus $200 million at Northern Pass; $1.7 billion of natural gas distribution rate base; and nearly $800 million of water utility rate base.

By the end of 2021, we expect rate base to total nearly $22.8 billion, including $1.6 billion for NPT.

In total, that represents more than an 8% rate base compound annual growth rate from 2017 through 2021.

NPT represents only 1.5% of that total compound annual growth rate.

We know that many of those on the call will take our CapEx and rate base forecast models and compare them to what we provided previously.

Slide 20 is designed to help you out by comparing our currently projected rate base at the end of 2020 of $21.8 billion with the $19.7 billion we projected a year ago.

The additional $2.1 billion comes from three primary sources: Aquarion represents $920 million of rate base by the end of 2020.

This wasn't in our forecast a year ago.

Additional transmission and distribution investments at our electric and natural gas utilities added nearly $600 million.

And tax reform also added nearly $600 million, for reasons I'll discuss in a minute.

And our Northern Pass estimate is roughly the same in both years, so has no impact on the increase.

As a result and as Jim mentioned, we have confidence in our ability to achieve our earnings per share growth rate of 5% to 7% through 2021 using our base of $3.11 per share that we earned in 2017.

We consider the 5% to 7% growth rate to be very resilient under a wide range of scenarios.

We understand that the market is currently giving us very limited, if any, credit from future Northern Pass earnings.

But our message today is that our company has a wide range of options to achieve its earnings growth objectives with or without Northern Pass.

Our new end-of-year 2020 rate base forecast, even without Northern Pass, is about $500 million higher today than it was a year ago with Northern Pass.

Also, we have a track record of identifying additional capital expenditure opportunities as we move through the forecast.

And our 5% to 7% growth rate assumes that O&M costs will remain essentially flat over the forecast period, as compared to our five-year O&M reductions that have averaged greater than 4%.

Also, unlike some of our peers, we do not need to issue equity as a result of tax reform.

Our solid financial profile, combined with constructive regulatory environments, fully regulated T&D business profile, our exit from generation and the addition of water distribution assets all support a low-risk business profile and strong credit ratings.

And we expect those ratings to remain strong going forward.

Slides 21 and 22 show how we expect the benefits of tax reform to flow overwhelmingly to our customers and be relatively neutral to us.

The new distribution rates, in fact, that took effect this month for our 1.4 million Massachusetts electric customers, reflect about $56 million of annual benefits from the reduction of the federal corporate tax rate from 35% to 21%.

Similarly, the three-year settlement we reached last month in CL&P's distribution rate case is expected to reflect about $45 million to $50 million, or similar amounts, of annual customer benefits from the lower tax rate.

The majority of our excess accumulated deferred income tax balances will be returned to our distribution customers over a longer period of time in accordance with the IRS regulations, very similar to the current process for tax purposes.

We will file details with our regulators on how the lower corporate tax rate will benefit customers across all of our operating companies over the next several months.

We expect very minor impacts from tax reform in our bottom line in 2018.

There will be a smaller tax shield from interest on our parent debt, but that'll largely be offset with other items.

We project an effective tax rate in 2018 of between 23.5% to 24.5%.

We also project paying federal and state income taxes of between $100 million and $120 million in 2018.

And unlike most or some of our peers, we were a cash taxpayer in 2017 as well.

Over the longer term, phasing out the impact of bonus depreciation beginning this year and the buildup of new deferred income taxes at a lower rate will lead to rate-base growth at a more rapid rate since accumulated deferred income tax balances are used in all our regulatory jurisdictions as offsets to rate base.

Turning to Slide 23 and recent regulatory developments, at the beginning of this month, we implemented new rate schedules for our Massachusetts Electric utilities.

Including the initial impact of the tax reform that I mentioned, the distribution rates for customers in Massachusetts actually declined by nearly $19 million.

As part of the Massachusetts rate decision, the Massachusetts Department of Public Utilities approved the merger of Western Mass Electric into NSTAR Electric effective at December 31, so you will no longer see stand-alone Western Mass financial statements.

The order also approved full revenue decoupling, and inflation-based adjustment mechanism that will allow modest annual increases at the beginning of each year for the next four years beginning in 2019, and a 10% ROE.

The rate decision also approved $45 million for the initial buildout of electric vehicle infrastructure and another $55 million to build battery storage on Cape Cod and Martha's Vineyard, both over the next five years.

Turning to Slide 24, in Connecticut, we reached our first settlement of a CL&P rate case in about 30 years, as Jim mentioned.

The settlement with the Office of Consumer Counsel and the prosecutorial unit of the PURA was filed with the commission last month, and hearings on the settlement were held this month.

The settlement terms called for a 9.25% authorized ROE with a 53% equity layer.

We are hopeful that the settlement, which includes a resiliency tracker, will allow us to avoid new distribution rate filings for a full four-year period.

A draft decision on the settlement is scheduled for next month, with the final decision on April 18.

New rates would be effective May 1.

In both Massachusetts and Connecticut, we believe we were able to achieve constructive outcomes.

We were able to demonstrate a strong ability to provide outstanding customer service reliability, while also effectively controlling our costs.

On average, as I mentioned, our O&M overall has declined by more than 4% annually since our merger was consummated nearly 6 years ago, including a reduction of about 3.5% in 2017.

Our reliability and safety metrics are also solidly in the top quartile of our industry peers, as we achieved our best-ever operating performance in 2017.

These constructive rate case outcomes allow us and enable us to continue to drive high levels of performance for our customers.

Turning to Slide 25, we and the other New England transmission owners continue to litigate the fourth transmission ROE complaint before the FERC.

Hearings were held in December, and an ALJ recommendation is due next month.

Meanwhile, we are awaiting a ruling from the commissioners on how they will address the court-ordered remand of their decision on the first complaint as well as initial rulings in the second and third complaints.

So our results and our guidance reflect the current 10.57% base ROE the FERC approved four years ago when it decided the first complaint.

Turning to Slide 26.

At the same time we were completing our New Hampshire generation divestiture, we concluded the purchase of Aquarion, moving out of a regulated business line with a declining rate base and moving into a business line with growth opportunities.

Beginning in 2018, we'll report Aquarion earnings as a separate business segment.

At the end of 2017, its rate base, about 90% of which is from its Connecticut operations, totaled about $770 million.

We expect that rate base will grow by 6% to 7% organically, primarily through connecting new customers, replacing older pipes and embarking on a new five-year project to move additional water supplies into the growing Stamford/Greenwich area.

In addition, in Massachusetts for Aquarion, we filed for an infrastructure capital tracker to accelerate main replacement and other reliability improvements.

We are proposing to use the deferred income tax flowback to fund these investments and mitigate the rate impacts to customers.

Aquarion's capital expenditures are projected to total $100 million this year, rising to $125 million by 2021.

Additionally, we expect Aquarion to continue to grow through future acquisitions of smaller water systems.

Aquarion had added about 11,000 customers through 2011 through '17 acquisitions, totaling 67 separate relatively small water systems.

All these acquisitions were in Connecticut.

With one minor exception, the full purchase price of all of these acquisitions is currently reflected in rates.

Aquarion has another four small water company acquisitions currently pending before the Connecticut utility regulators.

Aquarion has an impressive track record for outstanding customer service.

Its J.D. Power scores consistently rank at the top of the water utility industry and is viewed as one of the top places to work in Connecticut.

It's also a great fit for us and is supportive of our longer-term growth and environmental goals.

Before turning the call back to Jeff, I'll turn to Slide 27.

In December, S&P raised its corporate credit rating on the Eversource system to A+, meaning that we are now two notches above any of our electric utility peers holding companies.

Last month, Moody's also commented favorably on our Connecticut rate settlement.

Just to summarize on Slide 28.

We are a company that has a very long history of delivering on our commitments and a very strong track record.

Our earnings and dividend growth have outperformed the industry.

And as Jim pointed out, our total shareholder return has significantly outperformed the industry over many time periods.

Our ability to reduce costs since the merger by 4% to 5% each year, while also, at the same time, providing improved and top-tier service also sets us apart.

Our credit ratings have been raised repeatedly over the past 5 years, attesting to our strong focus on financial condition.

We continue to invest in our electric transmission and distribution infrastructure, and we are rapidly replacing older natural gas pipes and connecting new customers.

And finally, we're a close partner with our states and communities, executing on important clean energy initiatives.

Our 8,000 talented employees will work in lockstep with our nearly 4 million customers, providing great customer service to ensure their and our future success.

So I guess in recap, our major takeaways from this morning are, we continue to work on siting and building Northern Pass for all the benefits that had been described, for what it brings to New Hampshire and the region.

We're confident in our ability to achieve our 5% to 7% long-term earnings growth rate.

We have a plan to do that.

This will be achieved with an $11 billion capital plan, which is an 8.1% rate base CAGR, of which just 1.5% is from Northern Pass.

So we have confidence that we'll be in the 5% to 7% range in either scenario.

Long-term electric distribution rate plans are now in effect in Massachusetts and expected to be approved in the near future in Connecticut for implementation in May.

We have a long track record of being an excellent utility system operator, effectively managing, controlling and actually reducing costs and providing very high levels of reliability.

And we have a strong balance sheet, one that supports a tremendous amount of optionality to address new opportunities as they arise.

And finally, we're not significantly impacted by tax reform.

Our customers will reap the benefits of lower tax rates, and our credit profile will remain strong.

And additionally, we have no need to issue equity related to tax reform.

So with that, I'll turn it back over to Jeff.

Thank you, Phil, and I'm going to turn it back to Vanessa just to remind you how to enter your questions.

Vanessa?

(Operator Instructions)

Thank you, Vanessa.

Our first question this morning is from Shar Pourreza from Guggenheim.

So Phil and Jim, let me just bring this point again.

Without Northern Pass, you are comfortable with 5% to 7% growth with or without this project.

So just in light of what you're seeing with the rate base jump on Slide 20, how does sort of the growth look like with Northern Pass?

Because you seem to be comfortable without it at 5% to 7%.

So I'm kind of curious if Northern Pass doesn't move forward, where do you sort of land within your growth rate?

And then just as you think about your trajectory post how you're guiding, is there sort of enough projects needed to continue to be able to reiterate the 5% to 7%, given sort of what seems to be perpetual infrastructure needs?

Right.

So I guess, with anything Shar, there's many factors that influence where we end up in the range.

And certainly, with Northern Pass, again, that's more infrastructure investment.

Without Northern Pass, that's a little less infrastructure investment.

So just by definition, that would probably push you higher in any calculation range.

But you have capital plans.

We've demonstrated the ability over many years to add or find what needed reliability projects.

I think I've been asked in the past where's our list of projects to pull out.

And my answer is always, there's not a list.

It's really depending upon the reliability needs of the region, and we feel that we are in the best position to address them.

And we're good at identifying and moving those projects forward.

So I feel confident that, that will continue moving forward.

We have a great team in place to do that.

And as each of these projects goes in, it improves the reliability and helps lower cost to customers.

So you have that.

You have an ability to control cost that moves you around in the range.

You could have rate case outcomes.

Certainly, our recent Massachusetts case and, hopefully soon, we'll have approval in Connecticut, certainly provides a nice, strong, consistent framework that you can count on.

But there's always other rate decisions, talked about the FERC decision that's pending out there.

So we're comfortable that, for all those reasons, that we'll be in that range.

Okay.

Great.

That's helpful.

And just on Aquarion, Connecticut regulators clearly highlighted to us that they were big fans of the transaction.

So they touted it several times.

There are roughly 31 regulated water utilities that are within the state.

So I'm kind of curious how you're thinking about inorganic opportunities when it comes to water within the state or outside.

Yes, Shar.

This is Jim.

I'll just say that we just closed on this transaction 2 months ago.

And we continue to like the company that we acquired.

We continue to like the water platform and the growth opportunities, whether it's rolling up small communities of municipals, which they continue to do, looking at larger transactions, potentially even public water companies that are out there.

So I think that there's plenty of growth opportunity.

What you need to keep in mind is this is a company -- Eversource has a -- frankly, has a long track record of doing deals that are smart for our shareholders.

And so we will be delivering about what we do in terms of our next transaction, always with the shareholders' interest in mind.

Very fragmented space as you indicated.

There's something like 50,000 water companies -- entities nationwide.

So a lot of opportunity for rolling up additional companies and creating some standardization in efficiencies.

Got it.

That's helpful.

And just going -- if you don't mind me asking one last one, is thoughts on sort of the competitive process for wind going into the RFP without Northern Pass.

So what I'm asking is if Northern Pass ends up going to someone -- one of your neighbors, for instance, because Massachusetts can't wait for New Hampshire, does that actually indirectly position Eversource better for the next Massachusetts RFP?

So I'm sort of -- so you're sort of like the home team, and you could be left without any skin in the game.

So how should we sort of thinking about this indirectly through the RFPs?

Yes, I think we've always claimed that Northern Pass was not dependent upon any specific RFP.

You get a sense from my comments earlier and statements that the read coming from policymakers in the region, there's a tremendous appetite for clean energy solutions in the region.

We were thrilled to see the evaluation in Massachusetts conclude that the Northern Pass project was the most advanced and low-cost alternative out of the 46 that were bid.

So that tells us that we've got a very attractive project.

There are about 20 major permits that are necessary for a project like Northern Pass, and we're literally down to the final 2 or 3, including the 2.5 years for the Canadian approval.

So we have a project that is very advanced, very cost effective for customers.

It will serve them that way in the competitive solicitation.

So there will be an opportunity -- of interest in receiving power over that line.

It's just that we need to obviously make sure that we address the conditions and concerns that continue to exist in New Hampshire.

And our goal would be that the rehearing would give us an opportunity to do that.

Thanks, Shar.

Next question is from Caroline Bone from Deutsche Bank.

Just, I guess, on Northern Pass again, just to follow-up on that.

I mean, so are you guys -- is there going to be any waiting here for a final written order?

And how quickly do you expect the reconsideration process to go?

Carolyn, this is Lee.

We would expect to file for reconsideration very soon.

And the SEC essentially identified 3 areas that we -- they believe were deficient.

We will file reconsideration that -- cures that we believe would resolve their deficiencies.

And that should take place over the next 10 days.

So you mean when you actually file?

Yes.

Or when they respond?

Sorry.

Well, they have 10 days once we file.

We have 10 days to respond.

Okay, so even if you guys file something kind of new with these cures, would they have to respond to that in 10 days?

I guess the response could be something like interesting, we'll continue to look at this.

Or will they have to kind of give you a decision?

Well, what they do is they have to acknowledge whether they accept our reconsideration motion or not.

And then once they accept the reconsideration motion, then they would put together a schedule.

Okay.

Got it.

And then just back to, Lee, you mentioned that you were working with -- and this is on, I guess, a gas pipeline sort of solution that you're working with stakeholders in DC and New England.

What sort of solutions are under discussion?

And are you still focused on Access Northeast?

Or is there another kind of project you might be working on, too?

Yes.

I mean, I think the big picture on this one is that there's a growing emergence of leadership in the region, obviously, ISO New England, particularly key stakeholders inside of Massachusetts that realize that gas is not the enemy.

Gas is part of the solution.

If you want to ensure reliability, keep cost down and integrate renewables, then you want more gas, which is why we put those slides in there.

As I'm sure you know, all you have to go do is look how Texas, which is the fastest-growing economy in the U.S., energy usage is going up, costs are going down, and carbon's going down.

So the integration of renewables, particularly wind and gas, provide that certainty about the economic future of the region.

So again, in terms of projects, clearly it has to be a brownfield project.

Our Access Northeast project was essentially mostly brownfield.

We are looking at that to make that even more compatible and to have less of an impact on the environmental footprint that we have here in New England.

But I guess how do you get around the issue around how it gets paid for?

How are you addressing the issues that you ran into in the past?

Well, there's two paths here.

Obviously, there's the state path inside of Massachusetts, where you need legislation.

We have ongoing litigation in New Hampshire that we believe could resolve that issue at the Supreme Court.

Then there's always the federal path.

It's a longer, more complex path, but there is a federal path through FERC and ISO New England to put in place a tariff that will ensure sufficient fuel supplies and reliabilities.

So there's 2 paths here.

The state path, I think, clearly is more preferable just from the timing standpoint.

So we'll continue to work both.

Jim has met with FERC commissioners and FERC staff recently to discuss this issue.

So there is just this growing awareness that something has to get done.

And we continue to help to provide really information that is educational, that really gets people to understand gas is part of the solution, not the problem.

Okay.

Okay.

Maybe just one last minor one on -- I think Phil mentioned that you expected to pay $100 million to $120 million in federal cash taxes in 2018.

How does that compare to your expected book taxes?

For 2018, Caroline?

Yes.

I'm just wondering, it's -- that seems low.

I guess, I would have expected your book taxes to be higher.

And I mean, what's allowing you to defer federal cash?

I mean, did you guys have some sort of NOLs or credits that might be driving the difference?

Or maybe I'm just calculating it wrong.

Just regular timing difference.

But we expect the book to be higher, Caroline.

Thanks, Caroline.

Next question's from Michael Lapides from Goldman Sachs.

Two questions.

One, if the New Hampshire Site Evaluation Committee does not select Northern Pass after the reconsideration process, how do you think about the use of that capital that frees up on the balance sheet, given you wouldn't be making the capex tied to NPT?

So Michael, I think what we've always talked about, and I would still say, that we look first to redeploy that into infrastructure investments.

Talked about that over the last year or so in terms of, if we had cash and we use cash from the proceeds, from the generation sales to invest in infrastructure with our Aquarion Water transaction.

So our first look would be to develop additional regulated infrastructure.

Mike, this is Jim.

I think as Phil's commentary had mentioned that the 4-year plan without Northern Pass, so if you adjust out Northern Pass, it's actually a higher capital plan than what we had a year ago.

So we found some projects there.

I mean, if what you're getting at would be possible use it for share buyback, that's obviously an option that we have.

We're not announcing it.

We don't think that we need it necessarily to hit the 5%.

But it's a nice tool to have given our extremely strong balance sheet and our credit rating.

So I think we have a lot of optionality in terms of how we can deliver, as we have in the past, on our guidance.

Right.

That actually falls into my next question, which was, how do you think about what the right credit rating is for a company of your risk profile?

How do you kind of go through that quantitative analysis of like, what's the optimal credit rating for Eversource?

We don't actually sort of have as a target an optimum credit rating.

I think the recent experience of tax reform has sort of indicated that a lot of companies probably wish they hadn't levered as much as they had.

We're fortunate to be sitting where we are.

No equity issuance is needed going forward.

What we have offered in the past is top-tier financial performance.

And certainly, the total shareholder return slide that we have indicates that we've been able to achieve that.

Coupled with that top-tier financial performance is a little more in the financial condition, lowest risk in the industry.

That's an offering that we continue to have and we've enjoyed and our shareholders have enjoyed, having that balance of a strong financial condition along with the performance.

So clearly, do we need to be an A+, 2 notches removed from the next-best credit in the industry?

Probably not.

But we've been able to sustain that while putting up the earnings dividend and share price growth.

So I think long answer is that, basically, we don't have a targeted minimum credit rating that we're striving for, and we're going to continue to maintain a very strong financial position while we put up the numbers.

Got it.

Last item, and I hope Jeff doesn't kill me for asking 3 instead of 2. How do you, Jim, how do you and how does the board think about the environment for utility sector M&A given, a, higher rates and, therefore, higher potentially cost of debt; b, the impact on -- of tax reform and really what it's doing to your competitive balance sheet position versus other people's balance sheet positions; and, c, kind of the pullback in the -- the pullback we've seen a little bit in the equity of utility stocks?

Yes.

I guess, going to be situation-specific.

I think our board is thrilled with the outcome of the merger between Northeast Utilities and NSTAR.

I think we've exceeded their expectations.

I think the water acquisition continues to pay dividends and is an accretive transaction.

So we have a balance sheet and a currency that will continue to be strong.

But again, we have been a very, very disciplined player in that realm, and we continue to be.

It'll be, like I said earlier, transactions that are in our shareholders' best interest rather than growing for growth's sake.

Thank you, Michael.

Next question is from Paul Patterson at Glenrock.

All my questions have been answered.

But just back to Northern Pass, what's the viability for Northern Pass without the Massachusetts RFP?

Well, I mean, as Jim said earlier -- Paul, this is Lee.

We believe Northern Pass will be viable, especially if you look at the region and the region's goals around carbon reduction and renewable energy.

And here we are with essentially almost all of the permits complete.

There's, again, some almost 20 permits.

We're really are down to the SEC permit, and the Army Corps of Engineers permit comes from that.

So we have a project that will essentially be ready to go.

However, obviously, we need the SEC clearance.

So we believe, just looking at the Connecticut energy strategy, if you go look at the draft of bills that are inside the Massachusetts, all of them call for more hydro, more renewable energy.

So there'll be a home, as we've said many times in the past, for Northern Pass.

We just have to figure out what the timing of that is.

Okay.

So assuming that the NHSEC may not get back to you before the 27th, and they may go with the, whatever it is, the New England Clean Power Link, to go with the alternative Massachusetts stuff, you guys would -- what would happen in that scenario?

Would you guys continue with the -- would you start construction and everything if after that, you got the New Hampshire Site Evaluation -- in other words, if the NHSEC gave approval after the Massachusetts RFP had been selected -- had gone with somebody else, what would -- would you guys proceed with construction or what have you?

Or how would things proceed in that situation, I guess?

Paul, this is Jim.

Remember, we have a partner here in Hydro-Québec.

Hydro-Québec has expressed publicly a number of times their interest in exporting more energy, in particular, into the region.

I think that they would be interested in doing three Northern Passes.

So as long as they continue to sort of look to grow their bottom line by exports to New England, they would be interested in continuing with the project.

So we can't sort of speak independently about what that would look like that if Mass RFP went to other bids.

Keep in mind that projects that are being considered for that Mass Clean Energy RFP still have a long way to go, including the beginning of the process on the other side of the border, that took us 2.5 years to get the Québec approval.

So I don't think we need to sort of address that contingency now, other than to say that we've got a project that's highly competitive.

We proved that in Mass Energy RFP.

We have a partner in Hydro-Québec that's very committed and interested in exporting hydropower to our regions.

So that bodes well for this project going forward.

Okay.

And then just finally, I apologize if I missed this, what are the weather adjusted sales growth for 2017?

For electric, Paul?

Electric, yes, for electric.

Yes.

Yes.

It was slightly negative, less than 1%.

Thank you, Paul.

Our next question is from Greg Gordon from Evercore ISI.

Jeff, it's actually Durgesh on for Greg.

Jeff, we wanted to follow up and thinking -- you stated this in your prepared remarks.

The rate base on Northern Pass is roughly $1.5 billion, $1.6 billion, right?

And then the new rate base for 2020, with the tax reform and all the capex is roughly $2 billion higher.

So are we thinking about this the right way, that basically the reason why you're still comfortable with your 5% to 7% is essentially you have a $2 billion high rate base number on the back of CapEx and tax reform?

So even if you don't go ahead with Northern Pass, you can still get your '20 rate base numbers and your 5% to 7% earnings growth.

Is that the right way to put it?

Yes, it is.

That's the correct way to look at it.

Thank you, Durgesh.

Next question's from Julien Dumoulin-Smith from Bank of America.

It's actually Josephine here.

So I know we've kind of talked a lot about the Northern Pass already.

But I was just curious, how much Northern Pass earnings AFUDC is in the 2018 guidance?

What we said was -- I think Lee mentioned in his remarks, if everything were to progress during the year, there might be a small amount of capex, $300 million or so, started in 2018.

So this probably have a few cents related to AFUDC related to that.

Okay.

And then just on -- could you comment on where ROEs are trending at Public Service, New Hampshire and Yankee Gas after this cold winter?

And just thoughts on going in for a rate case in those jurisdiction.

Yes.

So we have not announced any plans to go in, but we do have, I mentioned in my remarks, that in each of the jurisdictions, we're looking to develop plans to how we're going to credit back the ADIT to customers.

So that could be an opportunity that during that process, that those 2 things could be tied together.

But we don't have plans there.

I would say that they're trending close to their allowed.

They're probably underperforming just slightly in both those areas.

Neither one of those have decoupled rates, but that would be something that we'd look to do if we went in.

Certainly, in New Hampshire, where we're divesting all the generating assets, it makes sense, at some point in the not too distant future, to make sure all the rates are reoriented that reflects the absence of generation.

Great.

And then just one last question.

I know it's late here already.

Could you just comment on where your ex loaded debt metrics are currently?

And kind of how much latitude there is for any transactions, returns of capital to shareholders?

Sure.

The FFO metrics are rating in the -- and we deliver in the high teens.

So that's where those metrics are.

So as Jim said, the balance sheet has capacity to throw optionality, and we you could take advantage of that.

But we're in the high teens, above the target ranges.

Thanks, Josephine.

One more question, and I think he's still online.

Praful Mehta from Citi, Praful, are you still on the line?

I think that's probably a no.

So all right.

With that, we don't have any more questions.

Thank you for joining us this morning.

I know we went over a bit.

But if you have any follow-up, please give us a call this afternoon.

Take care.

And thank you, ladies and gentlemen.

This concludes today's conference.

We thank you for participating, and you may now disconnect.