康涅狄格電力 (ES) 2016 Q4 法說會逐字稿

Welcome to the Eversource Energy fourth-quarter earnings call.

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

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

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

Thank you, John.

Good morning and thank you for joining us.

I am Jeff Kotkin, Eversource Energy's Vice President for investor relations.

We posted a slide deck on our website last night and will be referencing those slides this morning.

Now 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 US Private Securities Litigation Reform Act of 1995.

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

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

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, 2015, and 10-Q for the period ended September 30, 2016.

Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night on our website under presentations and webcasts and in our most recent 10-K.

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

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

Now I will turn to slide 3 and turn over the call to Jim.

Thank you, Jeff, and thank you all for joining us this morning.

I want to take a few minutes to provide some high-level comments on our 2016 accomplishments and our outlook for 2017 and beyond before turning the call over to Lee and Phil to provide the details.

Let me start with slide 4 by discussing our long-term vision for Eversource Energy.

We aspire to be the most successful and respected energy company in the country.

I think that involves Eversource becoming the primary catalyst for low-cost clean energy development in New England.

We expect to provide our 3.7 million electric and natural gas customers with superior service, which means top-tier reliability, prompt and responsive customer service, helpful insights into what drives energy use, and how customers can utilize their energy more efficiently.

We expect to partner in executing the energy strategies of the three states we serve.

And finally, we will help strengthen our communities not just on energy issues, but to support civic and charitable needs that are important to their economic vibrancy.

For investors, we expect to continue to provide you with the best risk-adjusted returns in the industry with very strong earnings and dividend growth paired with growing cash flows and an attractive balance sheet.

As you can see in last night's news release and on slide 5, we project annual earnings growth of 5% to 7% through 2020, using the $2.96 per share we earned in 2016 as the base.

We are confident that such a growth rate is very well founded and achievable under a wide range of scenarios.

Phil will provide you with some of the sensitivities shortly.

As you can see on slide 6, we raised the common dividend by 6.6% last year, and earlier this month, our Board approved an additional 6.7% increase for 2017.

These increases are consistent with our goal of raising the dividend at a rate that is consistent with our earnings growth.

Our payout ratio of 60% is relatively low for a regulated electric and gas company and our S&P ratings are the best in the industry, which illustrates the depth of our financial strength.

We chocked up a number of accomplishments in 2016 that were consistent with our long-term focus.

In terms of operations, you can see on slide 7 that we continued to provide top-tier service reliability for our customers and introduced a number of enhancements that will allow us to respond more quickly to routine and emergency requests.

We completed our $2.2 billion capital plan for the year.

We managed well within our operating budgets, which largely offset the negative impact of one of the warmest first quarters ever in New England, allowing us to finish 2016 within the earnings guidance that we provided to you a year ago.

Since our merger in 2012, we have reduced annual operations and maintenance expense by approximately $250 million even while measures of service quality have improved, and some have improved dramatically.

We also made significant progress in 2016 on our strategic initiatives.

In December, we announced the formation of Bay State Wind with Danish Oil and Natural Gas, the world's leading developer of offshore wind generation, to develop a 300 square miles offshore wind site on the continental shelf south of Cape Cod and the islands.

We will bid the project into the initial Massachusetts RFP for offshore wind this summer.

Also in December, we received Massachusetts regulatory approval for the construction of 62 megawatts of additional solar generation.

While in New Hampshire, regulators reiterated their support for the sale of 1,200 megawatts of PSNH's mostly fossil generation.

Also in New Hampshire, the Site Evaluation Committee appears to be solidly on a path to issue a decision on Northern Pass within the next seven months.

When taken together, you can see how we continue to position Eversource Energy as the leader in supporting our region's rapid development of clean generating sources.

Reducing the region's carbon footprint requires other initiatives as well.

First, it requires increased access to natural gas to provide both baseload energy and balancing resources that allow for the construction of more wind and more solar sources.

It also requires increased pipeline capacity to provide customers with the opportunity to change their primary heating source from oil to natural gas.

As Lee will discuss, we had some disappointments in 2016 on Access Northeast, but we and our partners, Spectra Energy and National Grid, firmly believe the project is critical to enabling the region to meet its energy goals and to keep energy affordable for our customers in the winter.

We all remain committed to its success.

As Phil will discuss, achieving our financial, operating, and strategic goals requires us to have strong trusting relationships with our policymakers, particularly our state regulators.

Three of the four electric distribution companies will have rate reviews this year, given the strong record of reliability and customer service we have had over the past several years and the significant reduction in operating costs that we have realized for customers.

We are confident in achieving reasonable outcomes in these proceedings.

For us, those outcomes will provide customers with continued improvements in service as we continue to invest heavily in our distribution systems while providing reasonable rate levels.

Finally, I want to stress the talent of our 7,800 employees who will deliver these excellent results.

And I'm so glad as CEO to say they delivered them in a safe manner.

2016 was in fact our best year ever for employee safety.

We went through a great deal of change in 2016 and we continue to perform extremely well.

Last May, Tom May stepped down from his great run as CEO.

And when I became CEO, Phil seamlessly moved into the CFO role.

We've been very successful lifting many of our operating metrics to the upper tier of the industry while lowering our costs through standardization of best practices.

Lee and his team continue to advance our new investment opportunities, whether they are Northern Pass, Access Northeast, Bay State Wind, Massachusetts Solar, or new opportunities in electric vehicle charging infrastructure and energy storage.

This strong performance explains why we're so optimistic about our future.

Now I'll turn over the call to Lee.

Okay, thanks, Jim.

And before I start, I will just say up front, excuse me for my voice.

I've got a little bit of whatever is going around here in February.

However, I will provide you with a brief update on our major investment initiatives and then turn the call over to Phil.

Let's start with Northern Pass and slide 9. The New Hampshire Site Evaluation Committee, or SEC, has set evidentiary hearing dates on the project, which begin on April 4 and continue through July 21.

We consider this schedule supportive of the SEC's stated commitment to issue a final written order no later than September 30, 2017.

The project also has secured a major legal victory on January 31, when the New Hampshire Supreme Court upheld a lower court decision, which found that the State Department of Transportation has exclusive authority to approve construction of utility facilities along and beneath state highways.

Project opponents have claimed the utilities are also required to obtain permission of adjacent property owners to construct facilities in the public right-of-way.

This was a very important ruling for the project, since 60 miles of undergrounding we proposed is largely under state and local roads.

Since our last conference call, interveners have filed their testimony and we have had the opportunity to query their witnesses.

Next week, several state agencies, including transportation, environmental services, and historic resources, are scheduled to file their recommendations on the project to the SEC.

Governor Sununu continues to be a strong supporter of Northern Pass, recognizing the billions of dollars of economic benefits it will bring to the state, in addition to the significant reduction in the region's carbon emissions: about 3 million fewer tons of CO2 annually.

He even mentioned the need for Northern Pass and the lower electric bills the project will bring to make New Hampshire businesses more competitive in his inaugural speech.

As you can see from slide 10, assuming we receive a favorable decision from the SEC in September, we expect to receive the US Department of Energy approval before the end of this year.

With those approvals in hand, we expect to begin construction early in 2018 and for the project to be completed by the end of 2019.

Our new capital forecast shows capital expenditures associated with Northern Pass of about $680 million in 2018 and $800 million in 2019.

We will have a better estimate on the final testing plan and in-service date later this year once we have more clarity on the SEC and the DOE approvals and the equipment manufacturing schedule.

We will bid Northern Pass into the Clean Energy RFP that Massachusetts will be running this spring.

Turning to slide 11, you can see that the legislation signed last August by Governor Baker authorizes the state's electric distribution companies to purchase 9.5 terawatt hours of clean energy, with the full amount contracted no later than 2022.

The initial RFP is scheduled to be released by April 1, 2017, or approximately 5 weeks from now.

A draft RFP issued earlier this month calls for bids to be submitted by July 27.

We believe Northern Pass is very well positioned for this RFP, which specifically allows large hydro to be eligible.

You will notice on the slide that the same legislation that created the April Clean Energy RFP also requires the state to issue an RFP by the end of June for a minimum of 400 megawatts of offshore wind, with the full 1,600 megawatts contracted by 2027.

As you can see on slide 12, and as Jim discussed earlier, we announced in December a partnership with DONG Energy of Denmark, the world's leading developer of offshore wind generation, to develop a 300-mile square track 15 to 25 miles south of Martha's Vineyard.

Our Bay State Wind partnership calls for us to share 50-50 in all development costs and associated benefits.

Bay State Wind ultimately can own enough wind turbines to generate at least 2,000 megawatts of clean renewable power.

This area is attractive because the water depths are relatively shallow, about 30 to 65 meters, and the wind speeds are high and reliable, resulting in high-capacity factors similar to baseload generation.

This is particularly valuable in the winter when electricity is more costly in New England due to our natural gas pipeline constraints.

We expect that once a winner or winners are selected, contracts with Massachusetts electric companies will be filed with the DPU in the first half of 2018, with commission approvals later in the year.

We would expect the permitting would take several years, with the construction not starting until after 2020.

As a result, the capital forecast we released today does not reflect Bay State Wind construction expenditures in it.

While our offshore wind opportunity is a number of years out, we expect it will be very significant.

As New England states continue to push toward a 75% to 80% reduction in carbon emissions by 2050, offshore wind will become an increasingly attractive option.

The experience in Europe showed a 50% reduction in construction costs over the past 4 years as a supplier network was built up, turbines became larger, and construction techniques improved.

Wind sites off of Southeastern Massachusetts are much closer to New England's load centers than onshore wind sites in Northern New England, and involve much less transmission construction and potential for schedule delays.

As a result, we expect offshore wind to be a very competitive renewable source of power in the Northeast.

Massachusetts also views offshore wind as a significant economic development opportunity.

Bay State Wind and two other firms that have secured offshore wind tracks south of Martha's Vineyard have identified New Bedford in southern Massachusetts as one of its potential staging areas for offshore logistics and construction.

Other states may also consider energy and economic benefits of this opportunity as well.

From Bay State Wind, I will turn to Access Northeast and slide 13.

You may recall that three of the New England states -- Connecticut, Rhode Island, and Maine -- passed legislation in recent years explicitly allowing their respective electric distribution companies to sign long-term contracts for natural gas pipeline capacity.

Each of these states has shown strong support for modernizing the region's natural gas pipeline infrastructure to improve energy reliability, reduce carbon emissions from coal, oil generation, and lower price volatility, and total energy costs for customers.

In fact, the Maine PUC last summer voted to move forward with Access Northeast.

Unfortunately, there is currently a lack of uniform energy regulatory policy across the New England states.

In Massachusetts, the Supreme Judicial Court ruled in August that the state's electric distribution companies could not sign such contracts.

And a couple of months later, the New Hampshire Public Utilities Commission said it could not approve such contracts under current law.

As a result, our focus is on developing a path forward that would continue to include participation of all New England states.

One option involves pursuing a change in the laws in Massachusetts and New Hampshire so that they align with statutes in Connecticut, Rhode Island, and Maine.

We also appealed the New Hampshire PUC order to the state Supreme Court, which agreed last week to consider the case.

Another avenue is to secure contracts with natural gas distribution companies in Massachusetts and other New England states.

We are not alone in wanting to develop a path forward.

In fact, all New England governments support a reasonable approach.

However, we need to resolve the issues in Massachusetts and New Hampshire to move ahead.

One fact that hasn't changed is the need for Access Northeast.

Wintertime prices in New England continue to be a couple of cents a kilowatt hour higher than they are outside the winter season.

This fact continues to add about $1 billion a winter to the cost of supplying the region's 6.5 million electric customers with electricity and requires the continued operation of older, higher-emitting generation such as coal and oil plants.

The differential is solely due to winter pipeline constraints, which lead to power plant curtailments.

The region's supply situation is illustrated on slide 14.

We simply don't have enough natural gas this time of the year to both heat our homes and businesses and to run the region's power plants.

Access Northeast is uniquely positioned to address this problem since it touches 60% of the region's gas-fired power generation.

The region's supply situation will worsen in June when the largest coal and oil generator, the more-than-1,500 MW Brayton Point power station, retires.

Pilgrim Nuclear Station is slated to retire two years later, and every baseload unit that is slated to enter service over that period of time is fueled by natural gas.

New England's natural gas supply situation may also worsen following the retirement of New York's Indian Point nuclear units, now expected to retire in 2020 and 2021.

It's likely that New York State will replace much of the lost Indian Point generation with power from new combined cycle natural gas units.

This would further tighten natural gas supplies as you move east from the Marcellus and into New England.

While that underscores the need for all of our major projects, it does not bode well for the long-term costs facing New England customers and is likely to have severe reliability impacts.

In Maine and New Hampshire, the issue of electricity costs continues to be a high-profile issue with manufacturers of products ranging from paper goods to firearms to chocolate saying they are having a difficult time competing with other regions of the country due to our high energy prices and the volatility of that energy.

Some of these customers have recently announced plans to expand or move current operations out of the region.

In his annual state-of-the-grid report three weeks ago and in the 2017 regional electricity outlook that was released yesterday, ISO-New England President and CEO Gordon van Welie warned that New England is challenged to meet electricity demands with existing fuel infrastructure, particularly during the winter.

He said market rules would need to change if we cannot invest in new gas infrastructure or allow increased use of dual fuel capacity, which will further add greater carbon to the region.

The clear message is that New England needs access to increased supplies of natural gas in the winter and needs it soon, unless it wants its reliability to be dependent on old units, oil and coal, built in the 1950s and 1960s that are past their efficient lives.

The recently concluded forward-capacity auction will likely place more pressure on the region's older oil and coal units.

Those units depend heavily on capacity revenues since they have very low energy revenues in today's market, especially during mild winters like we've had the past two years.

As you can see on slide 15, after peaking two years ago, capacity payments have declined in each of the past 2 auctions falling to $5.30 per kilowatt hour a month for the 12 months starting June 1, 2020.

We fully expect more of our older fossil generation units to retire in the coming years, only to be replaced by renewables and more natural-gas-fired capacity, thereby deepening the region's need for Access Northeast.

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

Thank you, Lee.

And today I have a few topics to cover.

One will be our fourth-quarter and full-year financial results.

I will talk about our 2017 and long-term earnings growth guidance; give you an update on several of our transmission projects; discuss several of the key state and federal regulatory dockets that we have pending; and provide some color on our new capital expenditure and transmission rate base forecast.

So let me start with the quarter on slide 17.

We earned $229.2 million or $0.72 per share in the fourth quarter of 2016 compared to earnings of $181.8 million or $0.57 per share in the fourth quarter of 2015.

Our transmission segment earned $0.33 per share in the fourth quarter of 2016.

That compares to $0.25 per share in the fourth quarter of 2015.

One of the two primary drivers for this earnings growth was higher transmission rate base, which is due to our continued investment in the reliability of the New England power grid.

And I will update you on some key reliability-driven projects in a minute, but the other principal driver was the settlement approved by FERC last month that allows us to recover certain merger-related costs through our transmission rates.

The settlement added $0.05 per share in the fourth quarter.

FERC had previously allowed recovery of these costs beginning in June and we had started recording that at that time.

But it was subject to a final decision.

On the electric distribution and generation side, we earned $0.26 per share in the fourth quarter of 2016 compared with earnings of $0.28 per share in the fourth quarter of 2015.

The fourth-quarter results decreased in 2016 primarily due to higher depreciation, property tax, interest, and bad debt expense, and partially offset by some higher distribution revenues in the period.

On the natural gas distribution side, we earned $0.08 per share in the fourth quarter of 2016, and that compared to earnings of $0.05 per share in the fourth quarter of last year.

Although still somewhat warmer than average, temperatures in the fourth quarter of 2016 were much colder than during the same period of 2015 when we experienced by far the warmest December on record.

Cold temperatures in 2016 resulted in a 22% increase in fourth quarter firm natural gas sales in 2016, as compared to 2015.

At the Eversource parent and other, we earned $0.05 per share in the fourth quarter of 2016 compared to a slight loss in the fourth quarter of 2015.

We benefited this year from a lower effective tax rate and the absence of $8 million of integration costs that were recorded in the fourth quarter of 2015.

Turning from the fourth quarter to the full-year results, we earned $942.3 million or $2.96 per share in 2016 compared with GAAP earnings of $878.5 million or $2.76 per share in 2015.

Those 2015 earnings included $0.05 per share in integration costs.

Transmission earnings totaled $1.16 per share in 2016 compared with earnings of $0.96 per share in 2015.

In addition to a higher rate base, 2016 results benefited from the absence of a $0.04 charge that we recorded in 2015 related to a FERC decision in the first return on equity complaint against the New England Transmission Owners and from the recovery of merger-related costs I mentioned earlier.

On the electric distribution and generation segment, we earned $1.46 per share in 2016.

That compares to $1.59 per share in 2015.

The decline was primarily due to the absence of $0.12 per share of benefits that we recognized in the first and fourth quarters of 2015 as a result of resolving multiple regulatory proceedings at NSTAR Electric, primarily involving recovery of bad debts and infrastructure investments.

Additionally, higher depreciation and property tax expense resulting from our ongoing investment in our distribution system reduced full-year earnings by $0.07 per share.

On the natural gas distribution segment, we earned $0.24 per share in 2016 compared to earnings of $0.23 in 2015.

A rate increase at NSTAR Gas and continued customer growth was partially offset by much milder fourth-quarter weather in 2016 impacting those results.

At the parent, we earned $0.10 per share in 2016 compared to a loss of $0.02 per share in 2015.

Much of that change was related to the absence of approximately $15 million of integration costs in 2015.

We also benefited from a lower effective tax rate during the year.

O&M continues to be a good story, a positive story for us and it was again in 2016, as our employees continue to provide excellent reliability for our customers while also reducing costs.

Lower O&M added $0.08 per share to earnings in 2016, if you exclude the benefits we recorded in the first and fourth quarters of 2015 when regulatory orders allowed us to reduce the level of bad debts at NSTAR Electric by more than $35 million on a pre-tax basis.

So, a positive O&M story again in 2016.

Turning from financial results to operations, our transmission investments totaled approximately $900 million in 2016 and that compares to approximately $800 million in 2015 and $700 million in 2014.

As you can see on slide 18, we progressed very well on a number of major transmission reliability projects during the year.

Through December 31, we invested $134 million in 28 different projects that together comprise the $560 million Greater Boston Reliability Solutions suite.

We expect to conclude the final Greater Boston work in 2019.

We have invested $117 million through 2016 in the Greater Hartford projects, which again are a variety of 27 different projects which together we expect to complete in 2018 at a cost of approximately $350 million.

All these projects listed here are progressing very well according to budget and schedule.

From operations, I will turn to our regulatory activity, and start in Massachusetts in slide 19.

On January 17, we filed electric rate reviews with the Massachusetts DPU for NSTAR Electric and Western Mass Electric.

While we filed two different sets of rate schedules, we have notified the DPU and FERC that we are seeking to legally merge the two companies in 2018.

From an operations perspective, they currently are operating on an integrated basis and providing excellent service to our 1.4 million electric customers in the Bay State.

The rate review calls for a modest increase in annual distribution revenues of about $60 million at NSTAR Electric and $36 million at Western Mass Electric.

As part of that, we are also seeking a performance-based ratemaking initiative which incorporates investments of $400 million of capital initiatives over the next 5 years.

That includes $120 million in new distribution automation, $100 million in energy storage, and $45 million in new electric vehicle infrastructure.

Additionally, we are filing for revenue decoupling at NSTAR Electric, and Western Mass Electric has had full revenue decoupling since 2011.

In terms of schedule, intervener testimony is due April 21.

Hearings are scheduled for June, with a final decision expected by the end of November of this year.

Our other general distribution rate review this year will be in Connecticut at Connecticut Light and Power, which we are required to file this June as a result of our 2012 Connecticut merger settlement agreement.

We expect the rate request at CL&P to be quite modest.

And really, in each of these rate reviews in Massachusetts and Connecticut, we present the compelling story of really dramatically improving reliability while reducing costs for customers.

Moving to slide 20, here we discuss possible impacts of any changes to the federal tax code.

While we expect Congress will start to address tax reform this year, I'm not sure that anybody -- and we don't know what the timing will be or how exactly the final tax reform will impact us or our customers.

Nonetheless, as a regulated T&D company, the vast majority of all the impacts of tax reform, including any cross-border tax if one were to occur, are likely to be passed through to customers in rates and revenue requirement changes.

As you can see on this slide, the customers would benefit obviously from a lower corporate tax rate as well as a potential refund of ADIT balances.

However, these benefits could be largely offset if there is a potential non-deductibility of interest or property tax or state income tax.

So much to be determined, but our efforts will focus on working with our regulators, legislators and the industry in general to ensure that tax code changes benefit our customers in the form of lower rates and protect our shareholder interests.

We expect a very modest impact on Eversource's ongoing financial results.

Lower ADIT balances would likely increase our rate base.

However, that could be offset if the nearly $60 million of parent interest is no longer deductible.

And we have very little in terms of unused tax credits, so minimal impact on Eversource.

Now moving on to 2017 and the earnings guidance, our guidance for 2017 is earnings per share in the $3.05 to $3.20 range.

And one of the assumptions there is we assume the current FERC ROEs remain in place of 10.57% ROE that we currently have in place, with a cap of 11.74%.

We continue to have multiple dockets around transmission ROEs pending at FERC.

The status of each complaint is noted on slide 21.

As you know, no decision was made on complaints two and three before the retirement of Chairman Bay this month.

So it may be a number of months before these complaints are decided.

From transmission, I will turn to generation, slide 22.

On December 29, the Massachusetts DPU approved an application from NSTAR Electric and Western Mass Electric to build a total of 62 megawatts of solar facilities in the Commonwealth.

We have commenced with the design and contracting, siting and permitting, and approval processes, and expect to invest approximately $200 million in these facilities this year.

In New Hampshire, the PUC has approved the auction process for PSNH's 1,200 megawatts of generation and published a schedule for the auction.

We expect the PUC to receive final binding bids in early August and close on the transaction prior to the end of 2017.

As you may recall, existing New Hampshire legislation enables the recovery of all of our plant investment through the sale through securitization if there's any stranded costs after the net proceeds of the sale.

Now I will turn to slide 23 and the capital investment plan that supports our 2017 guidance and our long-term 5% to 7% growth rate through 2020.

You can see that we project capital expenditures of $2.7 billion in 2017 and nearly $10 billion from 2017 through 2020.

These figures include $1.5 billion of investment in Northern Pass through 2019, and incremental investments in Access Northeast or Bay State Wind would be additive to the $10 billion figure.

There are a number of changes in this forecast as compared with the one we published a year ago that support our growth rate through 2020.

But let me just say upfront, if you take the time period from our last CapEx forecast, which included years 2017 through 2019, and you look at those very same years in this year's forecast, spending is up about $1 billion in that time period.

So let me get into some of the details of the plan.

First, as I said, there's additional capital spending in our forecast to really strengthen and protect our system.

Even though we have moved most of Northern Pass construction from 2017 to 2018 and 2019, we have identified other critical work for this year resulting in a capital budget for 2017 of $2.71 billion, which is consistent and slightly ahead of the $2.66 billion estimate for 2017 that we had forecasted at this time last year.

Transmission investments at our 4 regulated utilities are expected to total $950 million for this year as compared with $609 million we had projected a year ago.

We are forecasting $1.4 billion of transmission capital expenditures in 2018 and $1.2 billion in 2019.

All told, we expect to invest $3.9 billion in electric transmission over the next 4 years.

Estimated costs for the major transmission projects are very similar to what we projected last year: $1.6 billion for Northern Pass, $560 million for the Greater Boston suite of projects, $350 million for the Greater Hartford suite of projects.

The increased capital expenditures in 2017 and 2018 are really driven by a few items, including spending on critical infrastructure protection projects, storm hardening, and various projects related to reliability in terms of line replacement and pole structural changes.

On the electric distribution side, we are projecting investments of approximately $1.2 billion this year, including our solar investment, which I mentioned was $200 million.

And then approximately $900 million per year from 2018 through 2020.

Other than the solar investment, our electric distribution forecast is similar to what we had showed a year ago.

We have also significantly increased our projected investment in our natural gas distribution business.

As you can see on slide 24, in 2016, we invested approximately $270 million in that business segment.

And we have raised our capital investment levels in that segment over the next 4 years to total nearly $1.5 billion, including the $364 million in 2017.

There are a number of factors really driving the level of spending there compared with past years.

And the first is driven by state policymakers who want our older cast iron and unprotected steel pipe removed from our system at a faster pace.

We spent about $113 million on pipe replacement in 2016 and we expect to increase that to $118 million in 2017.

And that's a level we expect to maintain in the following years.

We are also at the early stages of a $200 million upgrade at our natural gas storage facility in Eastern Massachusetts for which we have a capital expenditure tracker in place.

That project should be completed in 2020.

As you can see from this slide, nearly 50% of all the natural gas distribution capital investment in the forecast is tracked through approved regulatory rate mechanisms, so we receive immediate recovery for that.

This includes the gas system expansion mechanism enabled by the Connecticut legislature several years ago that Yankee Gas continues to use to connect more residential, commercial, industrial, and municipal customers to its system.

Earlier this month, the Massachusetts DPU approved a much more modest but similar pilot program at NSTAR Gas.

Natural gas remains the fuel of choice for new construction in our service territory.

And depending on the type of oil our large commercial and industrial customers use, they can reduce their energy bills by nearly 40% by converting from oil to natural gas, even at today's oil prices.

Natural gas conversions also support Connecticut's efforts to reduce greenhouse gas emissions 80% by 2050.

A few years ago, we had projected that we would be able to double the earnings of our natural gas distribution segment from $60 million in 2013 to more than $120 million in 2023.

And we earned nearly $78 million in that segment in 2016, despite a very mild first quarter.

So you can see we are on plan to achieve our forecast.

You can see on slide 25 that over the next 4 years, we expect electric transmission and natural gas distribution to represent a larger share of our rate base, with transmission rising to 42% of our rate base and natural gas to 11%.

We project our overall rate base to total $19.2 billion by the end of 2019 and $19.7 billion by the end of 2020.

I should note that the 2019 figure is $900 million higher than what was in our projection a year ago.

Most of that increase, about $650 million, is attributable to investment in electric transmission.

The other growth comes from increased investment in the natural gas distribution pipe replacement and a recently approved Massachusetts solar program.

Investment in our system is expected to be the principal driver of earnings growth over the next four years, but another is the continued close management of our operating costs.

Over the next 4 years through 2020, we still have significant opportunities to reduce costs, but not at the same scale as the past four years, during which, as Jim mentioned, we reduced O&M about $250 million.

These costs reductions are being driven by our continued implementation of standardization and best practices throughout the Company and consolidation of several business applications to a more modern technology with greater functionality and flexibility.

All of these changes will make us even more efficient and better able to meet our customers' needs while lowering costs.

Lastly, I want to turn to our financing plans.

To start, I want to reiterate that we have no plans to issue equity over the next four years to finance our capital expenditures and dividend growth.

We expect many of our companies to issue debt during the year.

Debt issuances will result from a combination of capital expenditure programs and debt maturities, and we provided a list of this year's debt maturities in the appendix to the materials.

So in closing, we are very confident and we are very proud of our accomplishments over the past five years, and slide 26 illustrates the progress on multiple fronts.

We continue to be a company that delivers on its promises: improving service to our customers, addressing our region's unique energy challenges, and providing you, our investors, with above-average earnings and dividend growth while maintaining a high level of financial strength and stability.

I look forward -- and we all look forward to seeing many of you at our investor conferences coming up in Boston and New York over the next week.

And now I'll turn the call back to Jeff for any Q&A.

Thank you, Phil.

And I will turn the call back to John, just to remind you how to enter questions.

John?

(Operator Instructions)

Mike Weinstein, Credit Suisse.

Thanks for the very thorough update.

First question is on the ROE -- transmission ROEs.

Are you expecting any kind of impact from the loss of a quorum at FERC on the outcome for complaints two and three?

I'm sorry, Mike, you broke up there for a minute.

Could you repeat that?

Oh yes.

Are you expecting any kind of impact from the loss of a quorum at FERC on the outcome for the ROE transmission complaints, numbers two and three?

Quorum -- okay, that's the part I missed.

Just in terms of as I said in my remarks, we had expected and we had indicated we may get that decision in 2016.

So without a quorum, it is really anybody's guess as to when an order will come out.

So I think impact would be on a timing basis, but certainly the nature of who fills those seats could be impactful also.

So we will have to just wait and see, but we are expecting some decision in 2017 on those.

Right.

And then separately on Access Northeast, I'm sorry if I missed this, but have you guys discussed -- what is the next step there in terms of getting LDCs to contract for it or moving forward?

Mike, this is Lee Olivier.

We are having conversations with LDCs.

We have -- two states, Massachusetts and New Hampshire.

Obviously in New Hampshire we have appealed the lower court's rule onto the Supreme Court.

It has accepted it.

There is movement inside the financial legislature for a bill that would allow the PUC to review proposed contracts in the future.

And in Massachusetts, there is a -- really kind of an outreach campaign with key business leaders and legislators for them to understand the impact that not having additional gas pipeline capacity will have to the region, to reliability, to cost.

And as I mentioned, the ISO New England issued its New England electricity outlook yesterday, which paints a very dim picture.

They are also working on an analysis that will be out by midyear that will, we believe, specify what will have to take place in New England in order to ensure reliability, which could create a significant additional cost for the region as well as creating additional -- significant additional emissions to the region as well by maintaining older oil and coal-fired power plants and/or other sources of electricity to ensure reliability.

So we are working on all of those fronts.

Okay, that makes sense.

So basically it means waiting for that report to come out midyear before any further motion on it or --

Yes, I think New Hampshire will move along in a successful way.

I think it's really once that report comes out, it's really going to show the significant impact that we will face without additional gas pipeline capacity.

Right.

I wonder if you could comment a little bit on the Connecticut legislation that will allow the contracting of nuclear for clean energy purposes.

Where do you see that going forward at this point?

Yes, this is Jim, Mike.

We did file in that proceeding.

I think the fundamental question is one of need.

I think if Dominion can show sort of a need for some supplemental revenue stream, it makes it more compelling, I think, for their argument.

But there is already an existing process to follow in the region, and that is through the ISO New England process.

If they are actually planning on retiring the plant, they could file for that with ISO New England.

ISO could choose to give them a contract going forward.

Those costs would be spread around all of New England rather than burdening just the ratepayers in Connecticut.

So I think a lot of intervention is occurring in Connecticut and our position to that and we'll have to monitor it closely.

All right, all right.

Thank you very much.

Julien Dumoulin-Smith.

So perhaps just to follow up a little bit on what Mike was getting at a second ago, can you elaborate a little bit with regards to Access Northeast?

Is it possible to get just gas LDCs to make this project work?

Or to what extent ultimately are you dependent upon getting success in Massachusetts one way or another to get this project off the ground?

And then perhaps a third piece here is, is there a point in time at which you say this is a go/no-go on the project and/or pursue a new strategy, like, say, file at ISO New England with a tariff approach, for instance?

Yes Julien.

This is Lee.

The first question was can you make it work with just the LDCs.

The answer to that is no, you cannot make it work with just LDC load.

There is not enough LDC load to do that, so that will not work in the south.

The second one is that you really do need Massachusetts.

Massachusetts makes up about 42% of the load share in the region.

And you have the other states that clearly do not want to see Massachusetts create a free rider situation.

So you really have to have Massachusetts play.

And it's obviously in their best interest to do that.

And your last question about an option, which is filing a tariff at ISO New England and FERC and having FERC approve that.

That is an option that we are also looking at as well.

If you recall, the original option that NESCOE came up with several years ago was to use that methodology.

And then as a result of consultations with the then-FERC commission and staff basically said it would be cleaner if it was done inside of the state, which we still think that is true.

However, that is an option that we are looking at now.

Just to add in terms of the commitment.

This report -- I guess it came out of ISO this week, the ISO CEO says that he is concerned about keeping lights on in the coming winters.

So that creates a great degree of concern here.

Here at Eversource, we remain committed to the project.

Also if you look at what Spectra is saying in terms of their commitment, I think their earnings release emphasized the commitments to pursue a viable commercial model here to resolve the issue and the need that exists in New England.

Clearly, this is the last standing project, if you will, and it is the least I think onerous in terms of it being a brownfield project.

So we continue to remain optimistic.

As Lee indicated, there's actually a couple of potential paths to success here.

And we're actively looking at all of them.

Got it.

But just to be clear about it, for Massachusetts to be committed to the project vis-a-vis the rest of the region, that would be more than just an LDC commitment.

Yes, that's correct.

You essentially need EDC load to make this thing work in Massachusetts.

We would have to be committed to pay its load share percentage for that.

Got it, excellent.

Moving on to Northern Pass real quickly, can you describe a little bit the latest on the potential cost dynamics with further undergrounding?

As I understand it, I suppose this is still on the table in terms of a conditional approval out of the SEC.

Can you describe a little bit -- if you move to full undergrounding of all proposed elements, just how much of a swing factor are we talking about in terms of cost, just to give you some sense of magnitude.

And then to that point, how confident are you in having Hydro-Quebec committed to the project to the extent to which that there aren't -- need further required undergrounding as part of any conditional approval from the SEC?

Yes, I would just say, Julien, we're not anticipating any significant increase in undergrounding.

Clearly, we believe that if you underground the entire route, the project is not viable when you do that when you add in the additional costs.

We are not really pricing that out.

That would be a $2-billion-plus project.

It's not needed.

We think there is growing support in New Hampshire for the project.

Certainly we have a new governor that has voiced that support.

We have been very successful in the challenges that we've received against the project and the litigation.

So we're not anticipating significantly more undergrounding on their project.

In terms of the price, the cost of the project, we have still maintained approximately $1.6 billion.

Anything above and beyond that would be confidentially retained, because again we would bid this project into the RFP.

Got it.

Thank you all very much.

Greg Gordon, Evercore ISI.

I'd also like to reiterate, really thorough update, so, thank you.

Looking at slide 25, it looks like if I just do a simple algebra, the rate base growth forecast, including Northern Pass but excluding any Access Northeast or Bay State Wind capital, is about a 6% rate base CAGR.

Which, assuming that you can continue to earn consistent returns and you are not issuing equity, which you said you are not, would put you smack in the middle of the guidance range.

Is that the message you're trying to deliver here?

So Greg, you were a little faint.

But you are basically saying the rate base CAGR is about 6% per year over the forecast period, which supports the growth rate.

Right.

It seems like a very straightforward message, right?

6% rate base growth, no equity issuance, earn consistent returns.

That would put you right in the middle of your earnings growth target based on this rate base growth forecast, right?

Yes, we are not saying specifically what point we would be in the range, Greg, but certainly 5% to 7% we are very comfortable with.

The capital plan and what you have picked up in terms of the rate base certainly supports that.

I also mentioned that we still have some run room in terms of cost savings, too.

So those would be the two drivers to be in that range.

Fantastic.

And then at this juncture, just given the time horizon it would take to get resolution on a theoretical yes decision on Access Northeast, at this point, would the capital spend sort of theoretically not really start to impact your ability to generate earnings until the backend of this plan or maybe even into the 2021 type time frame?

Or do you actually think that there is a scenario where you could be in a go position to build that pipeline where it would have a tangible earnings impact inside this five-year plan?

Greg, this is Phil.

I think in Lee's remarks, he talked about not being in the front end of that process, but more in the backend in terms of Access Northeast.

So I would say your first assumption was accurate in terms of that it would be at the back end of the forecast that we provided.

Great.

Your comments on tax, Phil, make sense to me on just a federal income tax exposure.

But I just want to be clear that they did or did not encompass what might happen if you had an increase in bonus depreciation to 100%.

Yes, I don't think I commented on that, correct.

That is certainly -- as you know, there's many options out there and some of these options would affect everybody in the industry.

And then there's some who have more of a T&D profile like us, where there's not much exposure.

So I did not cover that, correct.

Okay.

Last question is for Jim.

Do you think that the Patriots are going to trade Garoppolo?

And if they do, are they going to let him stay in the AFC East?

Probably to the Jets.

And it will be the worst decision the Jets have made.

There's been a lot of bad decisions, so that'll be tough to top.

Thanks, guys.

Chris Ellinghaus, Williams Capital.

Phil, can you just describe the weather for the fourth quarter?

Was it close enough to normal that you didn't feel a material impact?

For the quarter?

Yes.

Well, actually, for the quarter, it was beneficial.

It was down from normal slightly, but it was up from the previous year.

It was close to normal, but probably even a little bit below when you look at the heating degree days.

Yes, I meant in terms of normal.

Yes, yes.

So below.

Okay.

And Lee, with all of the action in New England vis-a-vis Access Northeast and the gas contract in question, New Hampshire legislation, ISO statement, and you were talking about having an outreach with Massachusetts legislators.

Does this maybe give some momentum for Massachusetts to consider some legislation?

I think the more education that there is out there on this issue creates that impetus.

But clearly, I think the ISO New England action and their analysis that they are working on now will make a significant difference.

Because the outcome of that analysis is going to say that the status quo we believe will say it is not acceptable.

And if it is not acceptable and if you want to ensure reliability, here's what you have to do.

And it's going to be expensive, and it's going to create more emissions.

So for the folks that don't like gas and they want to see lower emissions, their outcome will create more emissions.

And that is what we believe this report will say.

And if the state and the region wants to meet its goals of this 80% carbon reduction by 2050, you must have natural gas to back up renewables and to ensure reliability and to ensure that the region stays competitive.

And I believe that that report will state that clearly.

Okay.

And Phil, looking at O&M for the year, even adjusting for some of the unusual one-time 2015 regulatory benefits, looks like the reduction was a little bit less than your targeted expectations.

Can you just talk about what challenges there might've been in 2016 versus your going-forward expectations?

Yes, I think that it is pretty close in that range, Chris, but we had a significant level of storms during the year.

So I would say when you ask what were some of the O&M challenges for the year, we had probably twice the level of storm activity in the region than we have had in past years.

And that puts some pressure on our response.

People working overtime, having to travel, those types of things.

So I would say that if we had a more normal weather year, you would see a lot lower O&M.

And you probably also see some better -- higher statistics, too, in terms of outages because bad weather and the stressed trees cause limbs to fall and outages to occur.

So I would say that would be one of the items.

Okay, great.

Thanks for the color, guys.

Travis Miller, Morningstar.

I was wondering on that 2020, the transmission spends.

That $283 million -- is that more along the lines of a normalized run rate number?

No, I think that in any of our forecasts, the out years, there is maybe a little bit less clarity in terms of specific projects, Travis, but that as we move through that forecast period, there will be projects that are identified.

I think you probably know our history, that until something has a pretty clean line of sight, it won't get into the forecast.

That's why we're so confident in it.

So I would say it's more a case of to-be-determined on some of those projects in that last year.

Okay, so like building blocks.

They start at the $283 million and then add on, say, Bay State and add on?

Yes, I think if I were to reconcile past forecasts, I would exactly -- that would have been the case, correct.

Okay.

And what is the status right now in terms of the carbon goals for the region, the RPFs in the states?

Where do you guys stand?

On track, ahead, behind?

Can you give me a sense for where you guys stand there?

Each state is a little bit different.

Connecticut really is a result of the major transmission buildout we did there over the last 10 years, and the retirement of a lot of the older oil- and coal-fired power plants and the lack of uplift.

Their carbon has come down fairly dramatically.

They are just about on target for their 2027 numbers.

Massachusetts has more of a gap, particularly as you have the retirements of Pilgrim, which is coming up in 2019.

So they have a lot more work to do, which is one of the reasons why the governor has sponsored the April RFP for large hydro and renewable.

And of course there is the June RFP for 2016, potentially up to 1,600 megawatts of offshore wind.

So he and they understand this and they are moving along rapidly to try to resolve this.

When you look at the other states, Maine's goal is so low to begin with.

It's like about 8% there.

They are pretty much there.

New Hampshire is very close to theirs, and Rhode Island.

So it's really Massachusetts would be the outlier for the 2027 era.

But then all of them would have to make significant cuts to get to the 2050 80% reduction goal.

Okay, great.

I appreciate it.

Praful Mehta, Citi.

So quick question on the tax reform part.

And wanted to understand from an offshore wind perspective, do the economics of offshore wind get impacted by the tax reform?

And how are you looking at other potential nonregulated investments to the renewable side and implications of that with the tax reform?

No, we don't expect that at this stage, Praful.

No impact.

Got you.

And just so I understand, that is -- why is that?

Because wouldn't that be a part of the economics of how you're looking at the project?

Well, it depends on what it is that you are -- what comes out of the outcome there.

And we have included in our analysis, Praful, no ITC or production tax credits associated with the project.

And just based on the high-capacity factors, the fairly significant and continuous drop in cost, we think it will be very competitive.

And as I said earlier, the beauty of this is its close to load.

You are not going to have to wait eight years or nine years to build a transmission project through three states.

So this -- it has a tremendous amount of benefits.

Yes, Praful, whether it's the solar investment that we have underway or the offshore wind investment, Bay State Wind, or the Northern Pass line, or we have actually announced electric vehicle infrastructure and battery storage pilots here in Massachusetts, all of them would benefit from a lower tax rate in that the effective cost of capital in each instance would be lower.

Got you.

But from a project perspective, the IRRs of, again, the nonregulated side, IRRs like the offshore wind, you don't expect much impact, given you are not really incorporating the tax benefits.

Is that a fair way to think of it?

That's correct.

That's correct, yes.

And then on the Access Northeast, we understood it.

And again, all the Q&A has been helpful.

But just so I understand, if it doesn't go through and if you do reach the point where from a go/no-go perspective reach the no-go, what do you have in terms of other backup plans in terms of CapEx spend?

Or what else do you think will be helping support the growth story if Access Northeast weren't to play out?

We update our forecast every year, and I think it is still indicated between 2017 to 2019.

We have increased our CapEx by $1 billion compared to where we were just a year ago.

So as we go forward in time, more opportunities will appear for us.

We don't anticipate Access Northeast being canceled, but each year, we seem to have more insight into capital needs of the system.

And my expectation is that there will be further projects for us to pursue.

Got you.

Thank you, guys.

Paul Patterson, Glenrock.

So -- and I apologize if I missed this, but the border adjustment tax, how would that impact Northern Pass?

Or the proposal for a border adjustment tax, if you follow me?

Yes, I think some of the things that we have seen or I've seen is that energy is not -- it could be something -- our energy and infrastructure is something that would not be impacted by that.

If you're looking at materials and procurement and things like that, most of our -- the highest preponderance -- the majority of materials that we purchase are domestic materials.

So from that standpoint, Paul, not much.

Okay.

Just so I understand, your understanding is that the border adjustment tax would not apply to things like electric power or natural gas or something like that.

Am I understanding you correctly?

Yes, I think that is a proposal, but that has been discussed as not being applicable to that.

Correct.

Okay.

And then do we know -- do we have a firm position from ISO New England whether or not Northern Pass would be eligible for a MOPR or not?

That's still under discussion right now, so no, there is no firm position.

And there won't be one until Hydro-Quebec would basically provide their indication that they would bid into the forward capacity auction.

So that's what it takes to trigger that review.

And so when would we get an idea -- when would that be, I guess?

When would that start to be bid?

Well, that would be obviously for the next auction.

And there is a letter that you have to trigger, and I can't remember exactly how many months' notice you have to give if you are going to participate in that.

But it could be triggered at that point in time.

Okay.

And that would be FCA 12 we would get an idea -- you expect that Hydro-Quebec would want to participate in FCA 12 as things stand?

I wouldn't speculate what they would want to do on that.

I wouldn't speculate for them.

Okay.

And then in New Hampshire, you guys have SB 128 for the gas, among other things.

And you have -- and you're also appealing things at the Supreme Court.

What do you think the -- I guess -- it wasn't really clear, I guess, in Massachusetts if you had legislation.

If you do have legislation, could you tell me what the number is on that?

You know, in Massachusetts, Paul, we don't have legislation at this point in time.

This is kind of a period of education, influencing, and anticipating the ISO New England study as well.

Okay.

And then just finally, there was an article -- a couple articles in the local press about 1 out of 4 -- about 25% of Connecticut customers being behind in their bills -- electric bills.

And I was wondering, is there any weather issue or fuel or -- was there something unusual about that?

Is that a normal number?

And just in general, how should we think about what that -- what the implications of something like that are.

I'm not familiar with the specific article, but we certainly have a lot of focus on our credit strategies.

We have implemented to the extent allowed under the regulatory mechanisms recovery and reporting mechanisms to collect.

So there's nothing unusual in Connecticut.

I think it's a matter of sometimes folks get behind on their bills and whether it be -- for a number of reasons, but there's nothing in particular that's going on there, Paul.

Okay, thank you very much.

Michael Lapides, Goldman.

Question, and this one is probably for Lee.

And apologize for making you use your voice today.

Real quickly, the economics of offshore wind, can we get some high-level differences?

We are pretty familiar in terms of the economics of onshore wind: CapEx in the $1,700 to $2,000 a KW range and transmission line miles.

If it's above ground, a couple million dollars per mile or so.

Can you talk about what the economics -- similar indicators are for offshore wind?

And if the numbers are more expensive, how different of a capacity factor would a typical or generic offshore wind plant likely get?

Just to say -- I wouldn't speculate at this point on the US numbers, because I'm sure you have looked up the European numbers and they are all in now below $0.10 per kilowatt hour.

That's well-known information of the most recent solicitations that have been done in Europe off of Germany and the Netherlands and so forth.

And that includes the transmission as well, and there's a few out there without transmission or even less than that.

And the real issue is they have a European supply chain that is there between Siemens and (technical difficulty) and the folks that make the towers and so forth.

And the real question is: how much of that are -- it's not a question of how much, but how soon can you get that kind of supply chain over to the US.

And as I've stated earlier, if you look at where this offshore wind would be interconnected from these leases -- the leases, once you land it onshore, the transmission grid in those areas has significant excess capacity as a result of the retirement of Brayton Point and Pilgrim.

So that cost will not have to be added to it.

It will be very minor.

So we see this being very competitive.

Our partners still see the costs coming down.

Obviously, they are the largest builder of offshore wind in the world.

They have very good positions in the various manufacturing queues.

And we think that the interest in offshore wind, it will spread beyond Massachusetts already.

The governor of Rhode Island sees it as a big part of their future -- energy future.

We think that's going to spread throughout New England.

Got it.

And when you think about the balance of needing more gas but having offshore wind that runs heavily in the first and fourth quarter, doesn't the addition of a significant amount of offshore winds in New England partially or significantly offset the need for incremental natural gas during winter peak?

I think from where we are now in terms of the shortfall of gas, and when you factor in another -- whatever, 6,000 or 7,000 megawatts of retirements of the older units, you've got to have gas.

And you talk to ISO New England, whether it's good and we'll always try the same thing.

On a winter's day at 4 o'clock when there's no solar and in a polar vortex, there might not even be much wind because wind drops significantly in a polar vortex, their job is to keep the lights on, which means you're going to have to have gas in that particular scenario.

So I don't think they see any way that you can maintain the reliability, take the volatility out of the region without having a gas supply into the region.

Got it.

Thank you, Lee.

Much appreciated.

All right.

Thank you, Michael.

I know we have kept you guys for a while today.

We really appreciate your time.

If you've got any follow up questions, please give us a call.

It looks like many of you have already moved on to the next earnings call.

So we will talk to you soon.

Thank you and have a good day.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating and you may now disconnect.