康涅狄格電力 (ES) 2014 Q4 法說會逐字稿

Welcome to the Eversource Energy earnings call.

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

(Operator Instructions)

Please note that the conference is being recorded.

Now I'll turn the talk over to Mr. Jeff Kotkin.

Thank you very much, John.

Good morning, and thank you for joining us today.

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

In addition to the news release we issued last night, we have posted a slide packet on our website at www.eversource.com, and have filed both the news release and the packet on our Form 8-K last night.

We'll be referencing those slides during our presentation.

So I'm going to start by turning to the first slide, which is the slide after the cover, and say that some of the statements made during this investor call may be forward-looking, as defined within the meaning of the Safe Harbor provision 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, 2013, and on Form 10-Q for the three months ended September 30, 2014.

Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and in our most recent 10-K.

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

Also joining us today are Phil Lembo, our Treasurer; Jay Buth, our Controller; and John Moreira, our Director of Corporate Financial Forecasting and Investor Relations.

Now I will turn over the call to Tom.

Thanks, Jeff.

Good morning, everybody.

Thanks for joining us on our first earnings call as Eversource Energy.

As you are all probably aware, we had a great fourth quarter, good sprint to finish the year very strong.

And part of that strong finish was announcing our new name.

Been in the works for about a year now.

You've probably heard me before say when we started this venture almost three years ago, I found six separate things doing things all their own independent way.

Didn't think that made a lot of sense.

Told our Board that we had 3.6 million customers, and they all want the same thing -- great service from a great service Company.

And we've been working on that for almost three years, integrating those six companies, standardizing, simplifying, significantly improving the service level, both our reliability, our responsiveness.

And as part of that, we've been preaching the One Company mantra.

And I thought the best way to do that is to get rid of all those old-fashioned brands and start with a new, modern brand.

And ergo, we now gave birth to Eversource Energy.

Our brand is all about customers, it's all about making the right energy investments.

We are, as I said 100 times, in the service business.

I'm a nut about service, and we want to be the source of all of our customers' energy needs.

We think we can have a lot of fun with the name going forward, to make it work to our advantage and to let the customers know that they are first in our minds and they're what we're all about.

Before I leave that topic, I would remind you all that effective February 19, we'll change our ticker symbol from NU to ES.

We're excited about that.

Just about everybody on this call, I think, will be on the New York Stock Exchange a week from today ringing the bell as we transition over to ES.

And we will ask our shareholders at our annual meeting this spring to formally change the name.

We'll be doing business as for a little while.

But we will formally change the name of Northeast Utilities to Eversource.

With that introduction, I would move you to what is slide 4, which talks about the components of our business.

I think you all are familiar that we view our business and we run our business as three separate and distinct business units.

We've got our transmission business, which we are excited about, and it continues to grow.

New England is in an interesting situation.

You know how we were in a bit of an energy crisis in New England.

And everybody recognizes that we have under-spent on our infrastructure, even though we have done a lot on the electric transmission side.

There is more to do if we're going to achieve all of our renewable goals.

And of course, on the gas side, last winter really exposed the weaknesses we had, the deficiencies we have, the under-investment we've made on the gas transmission side.

A little later in the presentation, I'll hand it over to Lee, who will give you an update on some of the exciting things we are doing.

Obviously, we have made great progress with Hydro-Quebec on Northern Pass.

They started in Canada very aggressively licensing their side of the line.

And we're going to be working very hard in 2015 to ensure that we get this over the finish line and the people of New England get the much-needed capacity that the region needs.

Plus the fuel diversity of this project, plus the renewable benefits.

And I think everybody is recognizing that Connecticut has recognized that they want to count that as renewable.

And I think that the new governor of Massachusetts is of like-mind -- just get the carbon out, and let's not be fussy about what we say qualifies or doesn't qualify.

So we're excited about that.

We're also working with our partner, Spectra Energy, on the Access Northeast Project.

We think it's unique.

There's a lot of stuff happening in the marketplace and a lot of conversation about the need for big pipelines.

We think we have the perfectly sized pipeline and that we are not just relying on pipeline to solve the problem, but also using peaking gas, LNG -- which, we have three facilities.

And with expansion, we think we will solve the problem in the most economically viable way of doing it.

On the electric distribution business, the key to it is to be sure that we earn our returns.

Jim will probably talk some more about that.

But he's had a very busy year on the regulatory front, a very successful year, and we've removed a lot of uncertainty, deferred costs, storm costs, about $0.5 billion that now are earning assets for us.

We're not only recovering them, but they're in rate base.

I have a simple model that says if we keep our customers happy, our regulators will be happy.

And if our regulators are happy, our shareholders will be happy.

We're happy to announce that we have had the best reliability ever in the history of the Company.

And most importantly, in Connecticut, which has had some problems in the past.

Again, we had a record year in terms of not only how few outages we had, but when we do have an outage, how quickly we snuff it out.

And that has not gone unnoticed.

It is showing up in our JD Power numbers and other places.

And on the gas side, we continue to grow.

We've been very fortunate.

We had a good year this year.

We met and exceeded our goal for how many customers we were going to hook up in the two states.

But we expect to add close to 150,000 new customers over the next 10 years, and this was all kicked off by Connecticut's wonderful comprehensive energy strategy that they adopted in 2013.

So it's exciting.

We are not only happy that we were able to execute on our plan this year, that we're able to step forward and play a leadership role in solving our regional energy situation, that we've been successful on the regulatory front.

But we think we set ourselves up for many years to come of good results for our shareholders.

And with that, I'll flip over on my favorite slide, slide 5, and mention that we had a good fourth quarter.

Through the first three quarters, we were running a little bit behind the industry.

And so I was glad we had a sprint, a good fourth quarter.

We came out a little bit ahead, as you can see of the EI index.

We really outperformed the S&P 500 for the year.

And that left us continue to build on this track record we have that on the 5- and 10- year basis, we're almost double what the industry has done.

And we're very proud of that.

And as I spoke earlier, the $3 billion of potential investment we have in Northern Pass and Access Northeast in the future, we think will fuel more of this growth.

That and our gas expansion initiatives.

So we think this is good news.

We think we've done pretty well in the past, but we don't spend too much time in that glory.

We reflect on it for a moment, and then we move forward and say -- what are we going to do going forward?

That's the important thing.

How do we outperform for the next five years?

The next slide, slide 6, I think is important.

Some people take it for granted, but I think one of the reasons our industry is in favor is because it has such a predictable flow of dividends.

As I look across industry in general, and I see what's happening to Coca-Cola and McDonald's and all of these other consumer favorites who are seeing their sales shrink, their profits shrink, that we start to look a lot more attractive against even the GEs of the world.

I think that when you can demonstrate that not only you can grow your dividend, but you can grow it at twice what the industry is doing, that you really deserve a premium.

And we think we are obviously a premium stock, and we intend to live up to that reputation.

Last week our Board voted to increase the dividend by 6.4% to $1.67.

And we just think that this growth rate puts us in a special class within our industry.

The last slide -- I'll mention slide 7 is, again, a slide -- I used it last year at our annual shareholders meeting.

Obviously you can see I'm going to use it again this year.

The merger that we entered into really has set the bar for what value can be created if the right parties come together and use the best of both, which I think we have.

I think we've taken the best elements of NSTAR, the best elements of Northeast Utilities, we blended them together to create Eversource Energy.

And we put a plan in place, we executed flawlessly on that plan.

It is the three-legged stool we talked about, with great opportunities going forward.

And of course, we are in the right geographies, as I mentioned before.

The world is looking at New England and saying -- you're so close to Marcellus, you should have low energy costs, you've got to do something about it.

And now I think all the governors our listening to us, and all the business community is looking towards us to see how we can help them to resolve these issues and get us competitive with the rest of the country.

So bottom line is, we're excited to take in a $9 billion enterprise when we put the companies together, turned it into a $17 billion enterprise with record levels of reliability and customer service, with great prospects going forward.

We're pretty excited about it.

I'm very proud of where we are as a Company.

I'm excited about what lies ahead.

And with that, so that you can get some sense of what lies ahead, I think I will turn the discussion over to Lee.

Thank you.

Okay, thanks, Tom.

What I'll do is, I'll provide you with an update on New England's power markets and our major capital initiatives.

And then turn the call over to Jim.

Please turn to slide 9, and we'll cover the impact of last winter's extreme volatility on today's New England power market.

The [cert] of the slide shows you what happened to market prices for both natural gas and power last winter.

Wholesale prices averaged about $140 a megawatt hour, or $0.14 a kilowatt-hour, in the first quarter of last year.

The mini-markets were caught short, especially during the second half of January.

And they had to enter into high-priced markets to acquire enough energy to meet their fixed-price requirements.

Hundreds of millions of dollars were lost, and some marketers went out of business.

Retail customers on the variable rate contracts saw their $0.09 per kilowatt-hour suddenly jump to more than $0.20.

Marketers did not make that same mistake this year.

They priced in a very large risk premium to safeguard against what happened last winter.

As you can see from the slide, average increase in fixed prices from the fall to winter of this year was 60%, compared with about 27% last year.

That is why you are seeing a lot of New England utilities with $0.14 and $0.15 per kilowatt-hour default in standard service rates this winter -- compared with $0.09 to $0.10 last winter.

The principal cause of this price escalation was the shrinking level of available pipeline capacity to deliver natural gas to power plants on cold winter days.

We believe that this winter's risk premium will only get larger.

We feel the winter constraints limiting natural gas availability to power plants are relieved.

New England's interstate pipeline system and level of LNG storage in New England are just inadequate for a region that continues to increase its dependence on natural gas for heating and power generation.

Moreover, the problem is getting worse as New England continues to lose its non-gas-fired generation.

At the end of last winter, the Vermont Yankee was retired, bringing to 1,400 megawatts the amounts of nuclear, coal and oil generation that was shut down in 2014.

That's about 5% of the region's projected peak load.

Turning to slide 10, you can see that plant retirements are pressuring capacity prices, as well as energy prices.

Costs coming out of New England's annual capacity auctions have escalated considerably in recent years, particularly in eastern Massachusetts and Rhode Island.

As many of you know, last week, the New England ISO held its Forward Capacity Auction for the 12 months beginning June 2018.

The results were good for plant owners, but expensive for consumers.

Because it was determined to be deficient, southeastern Massachusetts and Rhode Island cleared new generation at nearly $18 a kilowatt-month beginning in mid-2018, compared to a $3 per kilowatt-month today, and $7 a kilowatt-month beginning in 2017.

The rest of New England cleared at about $9.50 per kilowatt-month, compared with $3 today.

What this means to New England electric consumers is that total capacity costs have risen from an average of $1.2 billion a year for the years 2011 through 2013, to about $3 billion a year for the 12 months beginning June of 2017, and approximately $4 billion for the 12 months beginning June 2018.

And remember, this is in addition to the wintertime energy price spikes on the electric side we're seeing as a result of insufficient pipeline capacity into New England.

The frustrating thing is that significant natural gas supplies have never been closer to New England.

And when natural gas itself is relatively inexpensive in much of the nation.

Low-cost and abundant natural gas supplies are wonderful for our 500,000 gas distribution customers, since our Massachusetts and Connecticut gas utilities have storage and long-term contracts with the interstate pipelines that ensure the delivery of adequate supplies from the Marcellus and other sources, even and on the most frigid of days.

For our gas-heating customers, commodity costs continue to be very attractive.

The problem is really the electric side, and policymakers understand this.

We're losing our non-gas-fired power plants.

We don't have enough electric transmission to bring in alternative sources.

And we don't have enough natural gas transmission to keep many of our regions' modern gas units online when temperatures fall below freezing.

Additionally, we believe that pretty much all of the new-generation capacity that is being bid into the ISO auctions will be fueled by natural gas.

The New England States Committee on Electricity is very focused on these issues, and was charged by the New England governors to implement both gas and electric transmission infrastructure improvements.

Currently NESCO is working with states in southern New England on a regional procurement process for clean and renewable power.

Collectively, these three states -- Massachusetts, Connecticut and Rhode Island -- have legislative authority today to solicit 600 megawatts to 800 megawatts of clean and renewable power.

We believe this process will occur this spring.

Separately, several states are reviewing how to enable construction of additional natural gas pipeline capacity.

NESCO's work on a gas infrastructure initiative was put on hold last year while Massachusetts studied alternative approaches to meeting the state's demand.

The Massachusetts study has been completed, and it indicates a need, in the Bay State alone, for 600 million cubic feet to 800 million cubic-feet of new pipeline capacity.

And Massachusetts is not alone in concluding that more natural gas transmission into two New England is needed.

Connecticut officials also understand they need more natural gas for their merchant plants.

Maine already has secured expressions of interest for up to 200 million cubic feet a day.

With the momentum building, we expect the gas infrastructure initiative to move ahead.

As Tom mentioned earlier, we have the two best projects to address New England's drive to increase its firm natural gas supplies and its access to clean energy.

Those projects are Northern Pass and Access Northeast.

On slide 11 you can see that we expect the US Department of Energy to release its draft Environmental Impact Statement on Northern Pass Project in April.

Once that draft is released, the DOE will solicit both written and oral comments on its findings before the report is finalized.

Assuming that the draft is issued in April, we expect a file our state application with the New Hampshire Site Evaluation Committee around mid-year.

The committee will have up to two months to determine that the application is complete, and up to 12 months to rule on it.

While we wait for the release of the draft EIS, we will continue to reach out to various constituencies in New Hampshire -- including the neighbors of our proposed 187-mile route -- to understand any concerns they may have and try to address them.

As part of this effort, we expect to work within the ISO New England process to review additional project options that are consistent with the DOE -- what they are now reviewing.

We continue to project that we will receive both the state and federal approvals in mid-2016, and we'll be able to commence construction in the second half of the year, and complete the project in the second half of 2018.

Turning to slide 12, we continue to estimate a cost of approximately $1.4 billion for Northern Pass.

But that could change, depending on conditions attached to the regulatory approvals.

The project continues to offer enormous benefits to the State of New Hampshire, and to the region as a whole.

Those benefits would include a new baseload source of megawatts that would access one of the world's largest source of hydroelectric power.

The elimination of 3 million to 5 million tons of carbon emissions annually.

The creation of 1,200 construction and related jobs, many of which would be in northern New Hampshire, where unemployment is high.

Additionally, we are currently recalculating our estimates based on escalating prices for both capacity and winter energy in New England.

We believe that Northern Pass is likely to bring the region savings well-above $300 million annually.

And if you take a step back and look at all the benefits to the State of New Hampshire, they are significant.

In addition to the jobs noted above, there would be property tax income of nearly $30 million a year, based on today's rates.

We're also continuing to explore additional value we can provide to the state over and above New Hampshire's share of the energy and capacity cost savings I noted earlier.

In total, there would be several billion dollars in benefits to the State of New Hampshire over the next several decades.

Turning to slide 13 and Access Northeast, I'll remind you that this project is a $3 billion upgrade of Spectra's existing natural gas transmission system in New England.

It is being designed to deliver at least an additional 1 billion cubic-feet per day of natural gas to the region.

Unlike other natural gas transmission projects that have been announced in recent years in New England, this project is geared to serve both the LDC and the natural gas generation needs of the region.

Spectra Energy's pipelines in New England -- the Algonquin and Maritimes and the Northeast pipelines -- are uniquely situated to deliver increased quantities of natural gas to the region's newest and cleanest fossil generators.

Since the pipelines connect to more than 60% of the region's gas-fired units.

In December, we and Spectra announced the alliance with Iroquois Gas Transmission to provide the New England gas distribution companies and generators with additional access to Marcellus shale gas.

The alliance will allow natural gas to move from the Iroquois system in eastern New York to Access Northeast facilities in western Connecticut.

And then, to New England's generating plants and retail customers.

With Iroquois, we will connect to about 70% of New England's gas-fired plants.

Turning to slide 14, you can see the conclusions of a comprehensive analysis that was conducted for us by ICF International on the impact of Access Northeast.

This analysis, which will be released shortly, shows the dramatic impact that nearly 1 billion cubic-feet a day of gas would have had last winter if Access Northeast had been in service.

It would have lowered power costs by an estimated $2.5 billion.

Even in a normal winter, we believe it would lower costs for New England electric customers by over $1 billion.

That would result in a very quick payback period for a project that would cost about $3 billion.

Turning to slide 15, in terms of a timetable, we hope to conduct an open season shortly and enter into contracts with various New England electric and natural gas distribution companies by the middle of the year.

These contracts would then be submitted to state regulatory authorities for review and approval.

Also this year, we will begin work with regulators to determine the tariffs that would permit the electric distribution companies to contract with Access Northeast to develop capacity to fuel the region's gas-firing plants.

We hope to file our formal signing application with FERC in 2016, and to receive FERC approval in 2017.

That would allow Access Northeast to in-service by November of 2018.

Achieving the schedule would require regulators and state policymakers to act expeditiously.

On a separate note, I've discussed previously our efforts to parlay our success signing and building major transmission projects in New England into a business line, to partner with others around the country who might want to tap into our experience, our expertise, and vendor relationships of our transmission business.

We continue to speak with a number of other potential partners both inside and outside the northeast.

Now I'd like to turn the call over to Jim.

Thanks, Lee, for that comprehensive update on the challenging New England market and our solutions.

And thanks to all of you for joining us on today's earnings call.

My comments today, as noted on slide 17, will include a discussion of our fourth-quarter and full-year 2014 financial results, and our operating performance for the year.

We had a pretty full regulatory agenda in 2014, as Tom mentioned, so I'll cover our various regulatory developments.

Including key elements of the Connecticut Light and Power rate case, NSTAR's recent settlement of several items pending before the mass CPU, NSTAR's successful resolution of a long, outstanding issue involving supply-related bad-debt cost recovery and basic service rates.

The status of the Merrimack Scrubber proceeding and our motion to stay.

The current status of the ongoing NSTAR Gas rate proceeding, and the transmission ROE proceeding before FERC.

I'll also cover our expectations for 2015, as well as our financial outlook over the longer-term.

Including the major drivers of some details around projected capital expenditures and transmission rate base through 2018.

I'll conclude with a summary of how we've delivered on all the commitments that we've made since the merger.

Now, to begin, please turn to slide 18.

Yesterday we reported financial results for the fourth-quarter and full-year 2014.

As highlighted in yellow, earnings per share for the year, before integration costs, increased about 5% to $2.65, from $2.53 in 2013.

And our fourth-quarter EPS of $0.72 compares to $0.57 on a recurring basis for 2013, that's an increase of 26%.

The increase in the quarter is particularly noteworthy given the declines that we experience for both electric and natural gas sales of 2.8% and 4.8%, respectively.

As heating degree days in that service area for the quarter were about 10% below last year.

The most significant positive driver for the quarter was the $0.14 impact of low O&M costs, primarily reflecting a decline in labor-related costs, including pension, a lower level of bad debt expense, cost savings from our IT restructuring, and the acceleration of other merger-related integration initiatives.

Another positive driver in the quarter was the higher level of transmission revenues, which added $0.05 to our results in the quarter.

Reflecting ongoing transmission growth and the reversal of $0.03 of the $0.10 charge we took in the second quarter of 2014, due to FERC's review of the ROE earned by the New England transmission owners.

We made that change, as we think we now have more clarity on how the return should be calculated.

Electric distribution revenues provided $0.02 for the quarter, including the impact of new rates for Connecticut Light and Power that became effective December 1. Factors that partly offset the impact of these positive drivers were increases in depreciation, and property taxes, which together reduced earnings by $0.05.

And were driven by our continued investment in our electric and gas system infrastructure, and a $0.01 negative impact from all other items.

Turning now to our operations, as you know, service quality and reliability are always a key focus for us.

And the metrics on slide 19 and really show the key measures of our system reliability.

Looking at the great trend here, 2014 was the Company's best year on record in terms of reliability, as Tom mentioned earlier.

And that's after 2013 had previously been our best year ever.

The steady and dramatic progress indicates that our customers are experiencing 29% fewer outages than they were back in 2011.

And when we do have an outage, it is now 32% shorter in duration.

Significant improvements.

It's also important to note that we've achieved these great operating results in 2014 while continuing to take costs out of the business.

It's a model that works well for us, and one that we expect to implement well into the future -- providing quality service while maintaining a reputation as a disciplined spender.

At this point, I'd like to provide a brief update of the various regulatory items we've been involved with over the past several months, as listed on slide 20.

First is the base ROE proceeding before FERC.

As a reminder, in October 2014, the FERC issued an order on the first of three complaints, which confirmed that the base ROE should be set at 10.57%.

And that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness, which is 11.74%.

The FERC ordered the New England transmission owners to provide refunds to customers for the first complaint, and set the new base ROE prospectively from the order date.

In late 2014, those refunds began, and we expect the refund process to be completed by the third quarter of this year.

In November, FERC issued an order consolidating the second and third complaints for hearing and decision.

There will be a single decision for the issues raised in each complaint, and two different refund periods that the administrative law judge and FERC will have to consider.

The hearings before the ALJ are scheduled to begin on June 23, with a decision from the ALJ expected by the end of November.

The FERC estimates that it can issue its orders, absent a settlement, by September 30, 2016.

There's more to come on this, but our guidance assumes that the 10.57% base ROE approved by FERC in the first complaint will remain in effect.

Next on the list is CL&P's distribution rate proceeding.

Back in June, CL&P filed an application with the Connecticut Public Utility Regulatory Authority to increase distribution rates effective December 1, 2014.

The application requested an increase to base distribution rates, as well as increases for the annual recovery of previously approved 2011 and 2012 deferred storm restoration costs and electric system resiliency costs.

In December, PURA issued a final order approving a total distribution rate increase of $135 million, which includes a return on equity of 9.02% in the first year and 9.17% in later years.

It also requires a 50/50 earnings sharing mechanism for the next 100 basis points over the allowed ROE.

PURA allowed the case to be reopened for further review of certain deferred tax matters, that effectively reduced CL&P's distribution rate base in that proceeding by approximately $170 million.

If PURA accepts CL&P's tax treatment, it would provide an additional $22 million in revenues.

Much of the rate increase related to Connecticut Light and Power's recovery of 2011 and 2012 storm costs is over six years, with a full return.

The decision also allowed similar recovery treatment of $31 million of additional storm costs that were primarily incurred in 2013.

In addition, PURA approved the establishment of a revenue decoupling reconciliation mechanism effective December 1, whereby actual base distribution rate recovery is reconciled with a pre-established revenue requirement level on an annual basis.

Although we were disappointed with the allowed ROE, the ROE was certainly consistent with PURA's rulings in other recent cases.

And we do believe that the decision will allow CL&P's distribution segment to significantly improve its financial performance in 2015 and beyond.

Moving on to the comprehensive settlement agreement between NSTAR and the Massachusetts Attorney General's office that was filed with Massachusetts DPU in late December, this settlement resolves several pending matters.

In fact, 11 open dockets in total, including costs associated with safety and reliability programs, that were filed with the DPU for the periods 2006 through 2011.

We expect a settlement approval decision from the DPU in March.

Under the settlement, NSTAR Electric will refund $45 million to customers in 2015.

And we adequately reserved for those refunds.

Another positive development occurred just last month when the DPU issued an order allowing NSTAR Electric to adjust basic service rates to fully recover the supply-related portion of bad-debt costs.

An initial DPU decision several years ago would have disallowed recovery of that bad debt cost on a fully reconciling basis.

But we were successful in appealing the decision to the courts.

We're currently reviewing the DPU's decision with the Mass AG's office, so more to come on this.

Also in December NSTAR Gas filed an application with the DPU requesting a $34 million increase in base rates effective January 1, 2016.

The overall requested rate changes are necessary due to the significant infrastructure investment that the Company has made.

Additionally, earned ROEs at NSTAR Gas have been in the 7% range for some time, primarily because its distribution rates are by far the lowest in the state, and have been frozen in recent years due to rate settlements.

A procedural schedule has been issued.

Public hearings kicked off in January, and we anticipate a decision around October.

So we're still in the early stages of the proceeding.

Regarding New Hampshire generation, on December 26, we filed a motion to stay proceedings with the New Hampshire PUC regarding cost recovery for the Scrubber Project, in order to allow collaborative and legislative efforts to progress that may resolve the issues currently under consideration.

The PUC has accepted our motion, and we have commenced those discussions.

We continue to believe that all costs and generation investments approved and incurred on behalf of customers should be entitled to cost recovery.

To conclude my regulatory update, I will note that Connecticut regulations require a rate review every four years.

So we're currently anticipating that Yankee Gas will likely file for new rates in mid-2015, to be effective in early 2016.

Now I'd like to move to slide 21 to provide some guidance on what we expect as we move into 2015.

The future looks very bright, as evidenced by the guidance we noted in last night's earnings release.

We expect to earn between $2.75 and $2.90 per share this year.

Some of the earnings drivers include, one, higher distribution revenues to reflect the rate increase that became effective to CL&P.

Revenues will reflect the implementation of a decoupled rate structure with the return on the storm-cost balance.

Transmission revenue will continue to be a solid and stable driver to our earnings growth, as we move forward with the various projects that I'll cover in a moment.

Also, as a reminder, 2015 will not have the net $0.07 negative impact of the ROE charge that we took in 2014.

We expect to add another 2% to our gas heating customer base in 2015.

From an O&M perspective, we reduced our O&M in 2014 by 7%, and 3% in 2013, a performance that is well-above our guidance, and certainly well-above what other utilities are providing.

In part, this is driven by acceleration of certain merger integration initiatives into 2014.

We expect 2015 O&M reductions to be in the 2% to 3% range, but remain comfortable that over our forecast period, through 2018, it will average about 3% annually.

In 2015 a reduction in the discount rate used in calculating our pension costs from approximately 5% to 4.2% will be somewhat of a headwind in 2015, after it was a positive earnings driver in 2014.

Lastly, higher depreciation and property taxes in the distribution segments will continue to have a negative impact as they reflect the ongoing investment we make in our system infrastructure.

Higher interest costs and lower-base ROE on transmission will also have a negative impact in 2015.

Moving to slide 22, you can see that we've grown earnings nearly 8% on average over the past two years.

And we're pleased with where we're heading, looking in the longer-term, in terms of earnings prospects.

In yesterday's earnings release, we forecasted a long-term growth rate of 6% to 8% for earnings per share.

That's based off of 2014's recurring earnings of $2.65 a share.

We expect to achieve this growth over the period from 2015 through 2018.

The key long-term drivers are, one, continued growth in our FERC-regulated electric and now gas transmission businesses, including our Access Northeast Project with Spectra Energy.

Two, continued O&M reductions, which as I said earlier, we expect to average about 3% annually over the forecast horizon.

Three, gas expansion and system upgrade opportunities in both Connecticut and Massachusetts.

Four, revenue growth from modest distribution rate relief.

Five, offsets include higher depreciation and property taxes -- again reflecting our infrastructure growth and higher interest costs.

I'll note that there are no new equity issuances that are planned throughout our forecast period.

Slide 23 provides an overview of the progress we're making on a couple of major electric transmission reliability projects in Connecticut.

The Interstate Reliability Project should go into service late this year, and enhances our reputation as a premier transmission developer.

Also, we expect to make our initial state citing filing on the Greater Hartford Projects later this month.

On slide 24 you'll see an overview of actual transmission spending for 2014, and our plan for 2015 through 2018.

Last year we forecast approximately $3.7 billion in electric transmission capital spending from 2014 through 2017.

This year's forecast shows electric transmission investments of approximately $4.7 billion from 2014 through 2018.

After accounting for depreciation and deferred taxes, we expect our transmission capital program to add more than $3 billion to our transmission rate base by the end of 2018.

Moving on to slide 25, another contributing factor to earnings growth is our natural gas expansion, and the acceleration of the replacement of aging infrastructure.

Legislation in both Connecticut and Massachusetts provide us with important regulatory vehicles to expand our gas infrastructure to meet growing customer demand.

We expect new customer growth to continue.

For the second consecutive year, we added more than 10,000 customers, driven in large part by conversions to natural gas for heating.

The earnings contribution from our gas operations drove by nearly 20% in 2014 to $72 million.

We expect to increase our gas segment earnings by 50% by 2018, and double the gas segment earnings by 2023, as our customer base continues to grow and we make additional investments in our infrastructure.

Slide 26 provides a look at our rate base by business segment today, and where we expect it to be by 2018, given the growth in the transmission business, expansion of our gas operations and continued investment in electric distribution business.

I should add that this projected rate base, which we project will increase 37%, does not include the Access Northeast Project.

Before concluding my remarks, I'd like you to turn to slide 27 for a quick review of the commitments that we made a few years back at the completion of our merger, and how we've done against them.

On average, our 8% earnings growth and 6.5% dividend growth over the last two years have certainly exceeded the industry.

We have exceeded our target to reduce O&M costs.

We have maintained our strong credit ratings, which are among the best in the industry.

Reliability and service quality has improved to a level that is the best in the Company's history.

We continue to grow our business through transmission and gas expansion opportunities that are available to us.

We also continue to advocate for customers, proposing the Access Northeast Project and Northern Pass as very meaningful and cost-effective solutions to address the energy crisis we are facing in our region.

That concludes my formal remarks.

Now I'll turn it back to Jeff for questions and answers.

And I'm going to turn it back to John, just to remind you how to enter questions.

John?

Thank you.

(Operator Instructions)

Thank you, John.

First question this morning is from Dan Eggers from Credit Suisse.

Good morning, Dan.

Good morning, guys.

Just as a follow-up to the update on extension, the growth rate -- can you just explain to me, is Access Northeast in that number, both as contributing to the growth?

And then how is it getting reflected in the CapEx plans that you guys laid out in the slides today?

Sure, Dan.

Access Northeast is in our earnings projection.

Obviously, the spending is in the back end of the forecast.

We have not disclosed the annual capital expenditures associated with it.

We're giving the rest of the business' CapEx detail.

The reason for that is, we have a partner, Spectra, here, and we have not formally announced the cash flows collectively.

So we're trying to be respectful of that.

Okay.

And then, on the New England solicitations for clean generation -- where do you guys stand in that process?

And what is the talk of some transmission investment above and beyond what's in your CapEx budget related to those projects?

Dan, this is Lee Olivier.

That process, on the electric side, is still being worked through the NESCOE organization.

I think we can expect more information on that in the March timeframe, from the standpoint of what the schedule will be this year.

But we do expect that they would have a schedule that would conclude either late third quarter, early fourth quarter, and the selection of projects that would be funded through the NESCOE process.

This is on the electric side.

We have a number of other projects that we have ready for that NESCOE process, some of which would potentially interconnect into Maine to bring renewables down, interconnect into New York.

So we have a number of other transmission projects that would connect with renewables, and some of which could connect into one of the [number] clean energy as well.

So we'll be ready with potentially older another $1 billion of projects to enter into that process.

So the way we should think about that update probably being about a year from now, realistically, once the NESCOE process gets done?

And then you guys can assess what you would need to do.

Is that a fair assessment?

Yes, I think potentially late this year.

So if they run a bid process in late spring, they announce winners in the late fall -- we'll say the October timeframe potentially, November timeframe -- we would be able to announce where we stand at the end of that process.

One last question: You guys talked about the effect of the customers of the higher FCM clearing prices this year.

Was Northern Pass, and ergo, HQ, part of that bidding process from a capacity perspective?

And if not, does that create some relief next year for your customers as you think about the bidding process?

Again, they were not part of that bidding process.

They did bid in some other assets, but Northern Pass wasn't one of them.

And they would bid into the next Forward Capacity Market auction.

Okay, got it.

Thank you, guys.

Thanks, Dan.

Next question is from Michael Weinstein from UBS.

Morning, Michael.

Good morning.

It's actually Julien here.

Hey, Julien.

So a quick clarification on the last question from Dan, just before I get going -- if you did bid into the next FCA, you would indeed be able to take advantage of the exemption from NOPR, right?

The 600-megawatt [rudival] exemption?

I believe so.

We're still looking at that determination, but I believe so.

Okay, all right, great.

And then going back to the New Hampshire process in general, what's the timeline here?

If you think about go/no-go decision in terms of holding the Merrimack proceedings in advance here, when do we get a view as to -- yes, we're successful -- or -- no, we're going back to the prescribed track?

When do we get a view as to all of this coming together, in terms of gelling between the various issues?

Julien, this is Jim.

I would expect certainly over the next couple of months that hopefully there'll be progress there that could be announced.

Because obviously the proceeding is held in abeyance, and the PUC up there is looking for periodic updates as to how it's going.

So it's certainly, I think, a near-term process.

It's not likely to drag on indefinitely.

Great, excellent.

And then, Access -- you talked about kick-starting the process earlier this year.

Do you have any initial feedback?

Are customers able to afford and are they stepping up for your product, just as you think about the electric generators?

Particularly in the context of now having a firm pay-for-performance requirement that they'll need to meet in a time period in which the project will come online.

Have you noticed a difference in the receptivity of the generators?

It's a little premature at this point, because we have not announced our open access process.

We will do that -- perhaps as early as next week, we will announce that.

And then at that point in time, we'll be looking at whatever LDCs that want to sign on -- LDCs, generators, EDCs, and other major users of gas.

So I think it's premature to predict exactly where generators will be in this process.

Great.

And did I hear you say on the reserves for the ROE case, you took them back?

What drove that?

I think we announced, when we booked the charge for the ROE case, that we were very conservative in terms of what we booked.

And one of the conservative positions that we took back then had to do with how the cap impacts your incentive ROE.

And based upon how the refunds are calculated, based upon how the other utilities interpreted the order, we adjusted it to be consistent with everybody else's expectations, in terms of how that 11.74% cap impacts your transmission portfolio.

Got you.

And was there any data point that came out of FERC in particular that would've driven that view?

Certainly the refund that we've recalculated and the other utilities have calculated are based on that.

I believe there was some language in a MISO order that seems to suggest that our interpretation was correct as well.

Great; thank you, guys.

Thanks a lot, Julien.

Next question is from Travis Miller from Morningstar.

Good morning, Travis.

Good morning, thank you.

Generally on that 6% to 8% earnings growth number that you put out for the forecast, how do you think about the dividend growth off of that?

Obviously we have a lot of CapEx investment coming up.

And just wondering your thoughts on that trade-off between the CapEx and the dividend?

Sure.

We are re-confirming the earnings growth of 6% to 8%, but we are also are confirming that we expect the dividend growth to be consistent with that.

We think dividends can grow 6% to 8% over this timeframe if we have a conservative payout, about 60% or slightly below it.

We are retaining a lot of our earnings every year to basically fuel our capital programs.

So we're confident that we can grow our earnings and dividends at that 6% to 8% level going forward.

Okay.

Would that imply, do you think, a higher payout ratio as we get to -- call it 2017, 2018?

It should be roughly the same, 60%.

Okay.

And then, just real quick, how much was the pension contribution to the O&M savings in the fourth quarter or for the full year?

Whichever one.

We had IT outsourcing savings.

We had an actuarial pick-up on workers comp, other labor-related savings.

But the pension expense was a contributor to the fourth quarter, as it was all year.

I don't have the number, but it was a significant piece of the $0.14, for sure.

Okay, great.

Thanks a lot.

Thanks, Travis.

Next question is from Paul Patterson from Glenrock.

Good morning, Paul.

Good morning.

Can you hear me?

Yes, absolutely.

Okay.

On the Northern Pass, the regional funding opportunities, could you elaborate a little bit more on the potential process in that, and the amount?

You're referring to the NESCOE process, Paul?

Well, in the slide that you guys had, you mentioned participant funding, and then the opportunity for regional funding associated with the Northern Pass project.

And I was just wondering how that might actually take place?

Okay, well, the NESCOE process envisions, at least now, three different products.

One would be for renewable NNG -- that's Class I renewable energy -- wind is the big contributor there.

The other one would be for clean energy, and you have Connecticut.

And that three-statute is allowed to procure up to essentially 250 megawatts of clean energy.

I think Rhode Island is another 100.

So there's about 350 megawatts of clean energy.

The third part of this thing is infrastructure.

And it's about deliverability of energy.

So it's basically funding of infrastructure, which is transmission that interconnects with either clean energy, which is usually coined as hydro or renewable energy.

The way that would break down is that Northern Pass could play a role in the clean energy portion of this, and it could also play a role inside of the deliverability infrastructure portion of this.

At this point, we have to see exactly how much of each the NESCOE process will call for.

But that's how it can fit in, either into the clean energy products of approximately 350 megawatts, or into the deliverability infrastructure that would interconnect into hydro power in Quebec.

Okay.

But how much of the funding, the $1.4 billion, should we be thinking of coming from the regional versus the participant funding?

I think it's too early for us to tell.

We really have to see how that NESCOE RFP process is laid out, how it's structured, to determine -- and really, it's going to be ultimately HQ that's going to determine that.

Because it's essentially HQ owns the rights to that line and is the entity behind the participant-funded projects.

So it's really up to HQ to determine how much of that project would run through that NESCOE process.

Okay.

And then just to make sure I understood your answer to Julien's question with respect to the Forward Capacity Auction 10.

Your expectation is that this line would not be NOPRed, is that correct?

We're evaluating that now, but it's hard to say.

But we would believe that it's not NOPRed.

Okay.

Thank you very much.

Thanks, Paul.

Next question is from Steve Fleishman from Wolfe Research.

Good morning, Steve.

Good morning.

Just a clarification on Access Northeast with respect to your growth guidance.

Can you either be specific on how much earnings come from that or percent of growth rate?

Or if, for some reason it got delayed or didn't happen, would you still be within the 6% to 8% range?

I would say, worst-case scenario, if it didn't happen at all, we'd be at the very low end of the range.

Okay.

And then you'll give us more info once you know exactly what your interest is and the like?

Once we know what our interest is, and once we inspect or are comfortable with the cash flows.

To disclose it, we would do it probably together.

Great.

And just in terms of the FERC ROE thing, just so I understand -- you're now assuming, as the others, that the cap -- there's no other reason, and this cap is across your whole transmission business, not project by project.

Is that the change that you made?

That's correct.

Okay.

And just in the pending case, is there any way you can give a sense of, if you use the methodology that they have been using, what the risk to ROE would be?

Or is there a chance they don't use that same exact methodology?

There's certainly a chance that they don't.

We actually filed testimony on this on February 2, the transmission owners did.

And we applied the new methodology that FERC uses, this two-step discounted cash flow analysis, and think that applying that methodology supports the 10.57% that we're currently earning.

And then we provided a number of other analyses that had alternative benchmark methods that tended to support that level of returns as well.

So we remain confident that, that will be the likely outcome in that proceeding.

But it's a proceeding with a long tail, as you know.

It goes through late 2016 before we get a decision.

Okay.

One last question on Northern Pass.

You talk about how it's $1.4 billion, but depending on conditions, that could change.

Is it possible that, that $1.4 billion could become a lot bigger?

Is there any way to give us a sense of the range of potential change on that?

Steve, I think right now, that it would be hard to do that.

We've had or are having discussions with key stakeholders in New Hampshire.

We're looking at various configurations that are consistent with what the DOE is studying right now.

And I think it would be premature to say how much bigger.

Is it likely to be larger than $1.4 billion?

Yes.

I just can't tell you how much bigger because there's a big range of options around that project that we're evaluating right now.

Okay.

Thank you very much.

Thanks, Steve.

Next question is from Graham Tanaka from Tanaka Capital Management.

Graham?

Thank you.

Congratulations, good year.

I wanted to get a feel, if I could, for the long-term growth projections, and how much the organic -- on how much just simplistically will be coming from the large projects?

Just to get a feel for incremental growth.

Thanks.

We don't look at it that way.

As I mentioned, the latest project that was announced, Access Northeast, if that were not to happen -- and we certainly think it will -- it would put us at the low end of the range.

But we have a lot of major projects in there, including a $900 million increase in spending in transmission that we've disclosed here today.

So I wouldn't know where to draw the line, what's a major project and what's not.

But this is basically all organic.

It's all projects that are part of our core business that we execute, and there's no acquisitions in here or anything along those lines.

This is bread-and-butter work that we typically include in our forecast, and have a pretty good track record of actually implementing and executing well.

Great.

Just on the balance sheet side, just wondering what could be happening, what the range of change in leverage might be over the course of these projects?

What would the balance sheet look like, say, in 2018, 2020?

And then, if you could comment on the decline in interest rates.

It looks like your new debt is 120 basis points lower than retired debt, which is great.

And how that might reflect and what that's doing to the balance sheet and your earnings growth projection?

Thanks.

Certainly the projects that we're looking at that are in the back-end, whether it's Northern Pass or Access Northeast, is likely to involve some financing at the parent, not at the operating companies.

But in general, we target a capitalization ratio that's essentially 60/40.

And we continue to be very conscious of our credit ratings and the significance of those credit ratings, so we expect to maintain that high-quality rating that we have currently.

Cap structure, we don't see major changes.

The second question -- Jeff, could you clarify it for me?

Graham, could you just repeat the second part?

I was just wondering what would happen to the balance sheet at the end of the project.

You're suggesting that the cap ratios won't change much.

And then I was also wondering about the decline in the yield curve, the interest rate yield curve, and what that would do -- what you've assumed in your projections for earnings growth and the balance sheet, in terms of, if interest rates go back up or if they stay low.

Thanks.

The balance sheet -- you could do a pro forma run based on what we're giving you here for a capital expenditure forecast through 2018.

We have 35% or 40% growth in our rate base in that timeframe.

We have done a lot of financings; we've locked in a lot of low-cost debt, historically.

And we obviously have some debt financing going forward associated with these projects.

But we don't see it significantly impacting our balance sheet, whether interest rates stay where they are, or actually go up.

And Graham, we have a financial review that's posted up on our website that lists every debt issue on the system, and you can see what the rate is and what the maturity is.

So you could take a look at those versus where the markets are currently.

Yes, I was just wondering if rates went up a lot in this forecast period, if that would impinge on returns much.

And you're saying, suggesting, that you've locked in a fair amount, and the interest rate sensitivity is not that significant?

It's not that significant, and we have -- rates tend to be cost-based, so to the extent our financing costs go up, certainly in the transmission business, you get timely rate relief.

And we have distribution rate cases planned as well.

So to the extent we get increased pressure on our interest costs going forward, it's likely to result in higher rates to customers, and therefore we're somewhat insulated against it.

Thank you kindly.

Thanks, Graham.

Next question is from Caroline Bone from Deutsche Bank.

Good morning, Caroline.

Good morning.

Most of my questions have been answered, but just two more.

The first is on your gas customer growth projections, and what that assumes with regard to oil price?

Is that the current forward curve embedded in the outlook?

Or do you guys assume that oil prices increase to levels that we saw last year and before?

It assumes our current level.

Obviously the economics get tempered a bit when you've seen a major decline in oil prices.

But we continue to have great demand from our customer base, and we have two states that are interested in seeing conversions to gas take place.

So while the economics might be impacted slightly, we expect to achieve those targets given where oil prices are today.

Okay, great, thanks, Jim.

And my last question, this is a little bit more general, but things have obviously worked out quite well for you guys since the 2012 merger, and now you've changed your name.

So I'm just wondering if you could comment a little bit on your current thinking on M&A opportunities in this space?

Sure.

We continue to be a disciplined bidder.

If you look at the transactions that Tom led as CEO, the merger that formed NSTAR was accretive in the first year.

The merger that formed now Eversource was accretive immediately as well.

So we look at opportunities based upon the value to the Company.

And it's highly unlikely that we would do a transaction that would be dilutive to shareholders going forward.

The name change really had nothing to do with being constrained by Northeast in our title.

It truly was, as Tom indicated earlier, trying to bring together six different operating companies, each of whom have their own identity or culture or brand.

It really was driven by that.

The speculation about it being driven by an appetite to have a bigger footprint really isn't based on the situation here.

All right, thanks a lot, Jim.

Thanks, Caroline.

The next question is from Michael Lapides from Goldman Sachs.

Michael?

Hey, guys.

Congrats on a good year, and good start to 2015 as well.

A couple of things.

Just from a modeling perspective for understanding what you're assuming in your multi-year guidance, are you using the max on the zone of reasonableness?

The 11.74% is weighted average transmission ROE across the system?

We're assuming the 11.74% is the cap for the transmission portfolio in total, not project by project.

Right.

But not necessarily the cap, but I'm trying to think about what the weighted average would be.

And just trying to think about -- because you have some projects that, when they were granted, actually had way above that level -- Middletown-Norwalk, et cetera.

Those are now adjusted downward as we understand that.

And then the base ROE was a little bit different prior to incentives.

Just trying to think through from a -- what's in-guidance for an average transmission ROE across the system?

I'm trying to keep it a little simplistic.

Sure.

The base ROE, as we talked about, is 10.57%.

I would think when you looked at the various incentives that we earn on a number of the projects, the returns are likely to approach about 11.5% on a going-forward basis.

Got it, okay.

Second, I got a little confused by some of the comments about CapEx on transmission.

Because if I go back and look at the appendices and the Analyst Day from 2014, and look at 2014 to 2017 transmission CapEx in that slide, and then I look at 2014 to 2017 transmission CapEx in today's slide, they're virtually unchanged.

I mean, less than $100 million.

So I'm just trying to make sure I'm getting my arms around your commentary about a higher expected transmission expenditure going forward.

But when I just look at 2014, 2015, 2016, and 2017, the net number -- the sum of the four -- isn't really very different.

I would agree.

We've added 2018 this year, which is a number order of magnitude about $900 million.

But, yes, the transmission, cash flows, the transmission portfolio, near-term, really hasn't changed from what we -- changed that much.

Subtle shifts year to year.

But in the aggregate, you're right, it's in line with what we previously disclosed.

Got it.

Michael, I would add if you take a look at the components of it, which was in Jim's slide, you'll see that there is a lot of Northern Pass spending that was earlier in the forecast that we gave you a year ago.

And now it's later in the forecast, particularly into 2018.

So obviously there are a whole lot of other projects that have been added in those intervening years that get you up to the same amount.

So I think you have to look category by category to see how that occurred.

Got it.

And last thing, just on -- and thanks, Jeff, for bringing up Northern Pass.

Can you just give an update on where we are in the FERC EIS process?

And then what is entailed when you make your filing at the State of New Hampshire?

In regards to the EIS process, we would expect to have a draft EIS in the April timeframe.

It could be late March, beginning of April, but we expect to have it in April.

What we will do is, we will take that -- we have obviously been working on our filing for the siting valuation committee in New Hampshire.

We will take the information from the EIS; we will incorporate that as appropriate into our filing application.

Once we get ready to file, we put out a notice, which is a two-week notice that basically says we will conduct hearings in the five counties in which the line is in.

There's five different locations.

It will take about two weeks to run through a town hall meeting process in New Hampshire.

And then there's about 30 days or so where you solicit feedback and comment; you take that into consideration.

Then you make your filing.

And then the state has essentially -- it's got up to 60 days to accept your filing as complete, and then have up to 12 months timeframe in which to render a decision.

Obviously, in the interim of all of this, in the background of this, is that we will be having discussions with various key stakeholders in the state to try to reach what we think is an acceptable configuration in other aspects of the project, in terms of the economics of the project for the state.

So that will all be going on in the background.

We hope to reach a conclusion on the background discussions later this year.

Got it.

And just big picture on the Northern Pass, I mean, this is the second or third time where you've pushed the CapEx out significantly into the outer years.

What's your level of conviction that you're getting closer to having a finalized schedule for Northern Pass versus a -- hey, this is still very much an early estimate and things are likely to move around a lot, whether it's on timeline or cost?

I think on the schedule -- I'm very confident in that schedule.

It stacks up very well with where the processes are.

Obviously, this project has evolved over the last five to six years.

We know a lot more about the technology.

We know a lot more about the political situation.

We have worked extensively in the communities in which the line will be placed, or built.

Needless to say, the energy environment in New England has changed radically.

There is, by and large, consensus everywhere that the project is needed.

There is still some, obviously, disagreements about the configuration of the project, which are the things that we have been working on.

So I am actually very confident.

That's a good estimate.

I think the $1.4 billion -- as I said earlier, it's likely to be more than $1.4 billion.

But it's premature, I think, for us to forecast that today.

I would think perhaps within the next six months we will have a much better sense of that.

Because we'll be closer to what we believe is an acceptable configuration for the key stakeholders in New Hampshire.

Got it, Lee.

Thank you, and thank you, Jim and Tom, as well.

You're welcome.

Thanks, Mike.

Next question is from Andrew Weisel from Macquarie.

Good morning, Andrew.

Good morning.

I'll keep it short, given how long the call has been going.

On Access Northeast, I think you said to an earlier question that the open season would be first geared toward electric generators, and then LDC customers next.

My question is, if NESCOE doesn't move forward at the pace you laid out, is there a point where you would start to move forward on the projects for a smaller LDC-only one?

And if so, at what point would you make that decision?

Andrew, when we do our open season, it will be for both LDCs, EDCs -- it will be for generators and any other large users of natural gas.

It will be for all of those.

And so we'll run through that process, we'll see what comes out the other end.

We know there are other EDCs that we have talked to in the region that have reviewed the project, think it's the right project for the region.

So we know there will be EDCs that will sign on, and we know that there will be LDCs that will sign on.

Really, once we come out of that, we believe we will have a demand for gas that will support a larger configuration.

At which point in time, we will propose the configuration through the regulatory bodies and ask for either approval to go ahead -- very similar to what you would do on the LDC side of the business -- or we will determine what an alternative process is with policymakers and regulators of the states.

So does that mean that with or without Massachusetts signing on to the NESCOE initiatives, the timing would be fairly unchanged?

I think that our timing is good, because there will be -- like we said, we know there will be some LDC demand.

And the conversations we have had with the leadership of key states, they indicate that we need to move on; that the sooner this project gets in-service, the sooner we start realizing that $1 billion of savings a year.

And also, we don't talk much about this, but the ongoing retirements that we have in New England and the shortage of gas for the existing plants -- those are going to provide a significant threat to reliability.

ISO New England has made that statement, that this is not only an economic issue where people pay a lot of money.

But it's a real challenge to the reliability of the region's grid.

The governors understand that, and they want a solution.

So we're confident that we, working with the key policymakers of the region, will come up with that solution.

Okay, sounds good.

Then lastly, I want to ask quickly about bonus depreciation.

What do your rate-base forecast and your cash flow assumptions assume around bonus depreciation?

Bonus depreciation in 2014 was about $500 million.

So there's a little bit of an earnings drag associated with that, that penny or two.

It's great cash flow impact and for 2015 --

It's about $175 million impact in accumulated deferred income taxes, Andrew

Great.

Thank you very much.

Thanks, Andrew.

Next question is from Felix Herrmann, or maybe [a shar] from [Vivian].

Good morning.

Good morning, guys.

Just to clarify on an earlier comment.

We said that without Access Northeast, we expect to grow around 6%.

And then as that project comes on in 2018, we expect to see a bump in EPS around there.

Can you just clarify that?

Yes, the question was without Access Northeast in the forecast horizon, where would earnings likely be?

And I did say the low end of the range.

I want to point out that the cash flows for Access Northeast are likely to be beyond the timeframe here.

There will be certainly spending in 2017 and 2018, but also in 2019.

So the comment that I did make was, the low end of the range without that project.

Okay, thank you.

Great, thanks, Felix.

That's it in terms of questions this morning.

We really appreciate everybody joining us.

If you have any additional questions, please call John or me later today or tomorrow.

Take care.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.