康涅狄格電力 (ES) 2014 Q1 法說會逐字稿

Welcome to the Northeast Utilities earnings call.

My name is Christine, and I will be the operator for today's call.

At this time all participants are in a listen-only mode.

Later we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr. Jeff Kotkin.

You may begin.

Thank you Christine.

Good morning, and thank you for joining us today.

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

Speaking today will be Jim Judge, our Executive Vice President and Chief Financial Officer; and Lee Olivier, our Executive Vice President and Chief Operating Officer.

Also joining us today are[Jim Munce president of our transmission business, Phil Lembo, our treasurer, Jay Buth, our controller and John Moreira, our director of corporate financial forecasting and investor relations.

Before I turn over the call to Jim, I would like to remind you that 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 risks and uncertainties with may cause actual results to differ materially from forecasts and projections.

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

If you have not yet seen that news release, it is posted on our website at www.nu.com and has been filed as an exhibit to our Form 8-K.

Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10K for the year ended December 31, 2013.

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

Now, will turn over the call to Jim.

Thanks, Jeff, and thank you, everyone, for joining us this morning.

We appreciate that you are spending some time with us today.

In my remarks today I will cover our solid first-quarter earnings results, some recent financing activity and the highlights of economic conditions in our region, and I will conclude with an update on various regulatory proceedings and legislative activity impacting our companies.

You probably with our first-quarter earnings release that was issued late yesterday.

We earned $241.8 million, or $0.76 per share on a recurring basis this quarter compared to $229.9 million, or $0.73 per share last year.

These results exclude integration costs of $5.8 million in 2014 and $1.8 million in 2013.

We are off to a good start for the year and feel comfortable with the full-year earnings-per-share guidance of $2.60 to $2.75 and our longer term EPS growth rate of 6% to 8% through 2017 that we provided you at our analyst day in February.

Our 6% to 8% sustained EPS and dividend growth and very strong credit ratings really differentiate North East Utilities from other investment opportunities in our sector.

As you might have expected, a major factor in the quarter's performance was cold weather, with temperatures well below last year and well below normal.

Heating degree days on average within our three state service territory were up about 15% this year compared to 2013.

As a result, we experienced a 4% increase in electric sales for the quarter compared to last year and a 15.5% increase in natural gas sales.

These higher electric and gas sales added $0.07 to earnings-per-share for the quarter compared to last year.

I should note that if you were to weather normalize our sales variance, electric sales were up 1.3% and gas sales increased 3.6%.

So, we saw some growth in sales beyond the favorable weather benefit.

This growth is evidence of the recent favorable economic data in our region, which I will discuss later.

Another as a positive driver was the decrease in operations and maintenance costs that had an earnings impact during the first quarter this year, which improved earnings per share $0.02 for the quarter.

The two biggest drivers there were lower pension benefit costs, which we discussed during our analyst day as being a significant driver of lower O&M for the next few years, and a reduction in storm costs.

You may recall that last year we incurred significant storm costs as a result of wintery weather.

While most of these costs were deferred, some were not.

So, storm costs that affected first-quarter earnings were lower as compared to 2013 first-quarter levels.

While storm costs can vary with the weather by quarter, other O&M reductions are more permanent.

One small example of this is our initiative on targeted customer outreach in 2013 to enroll customers in our e-bill program.

Since the merger closed two years ago, we have doubled the number of customers who received electronic bills, achieving top quartile performance for each operating company, and saving more than $1 million annually on postage expenses, a small success story that we're quite proud of and an example of our focus on adopting best practices post merger.

Let me remind you that our guidance calls for a decline in O&M of about 4% for the full year 2014, so we expect to see continued savings in this area as the year progresses.

Our transmission segment earned $74.9 million in the first quarter of 2014 compared with $79.9 million in the first quarter of 2013, a decline of $5 million, or $0.02 per share.

Essentially, that entire decline was due to a higher effective tax rate.

You may recall that last year's transmission results included the favorable impact from the resolution of state tax audits.

That item boosted 2013's first-quarter earnings by $13.6 million, or $0.04 per share on a consolidated basis.

About half of that $13.6 million benefit was in transmission and the other half was in NU parents and other.

As a result of the higher effective tax rate, NU parent and other Company earnings declined $2.6 million in the first quarter of 2014 from $7.2 million in the same quarter of 2013.

Moving on, an increase in depreciation in property taxes reduced the quarter's results by $0.02 compared to last year and is a reflection of the continued investment in our system infrastructure.

While interest expense was not a major positive driver in our earnings performance for the quarter, we continue to take steps to lock in low interest costs through some recent successful financing activity.

In January, Yankee Gas issued $100 million of 30 year first mortgage bonds with a rate of 4.82%, mostly to repay a $75 million debt issue that was also paying about 4.8% that matured the first of the year.

In March, NSTAR Electric issued $300 million of 30-year debentures at a rate of 4.4% to repay a like amount of 10 year 4.875% debentures that matured in April.

More recently, CL&P sold $250 million of 30-year 4.3% first mortgage bonds to pay off $150 million of 4.8% bonds that mature later this year.

So, we continue to take advantage of the current favorable interest rate environment by locking in some long-term financings that will benefit customers over the long run.

We expect that our ability to continue to obtain favorable interest rates will continue as last Friday, Standard & Poor's raised its outlook on NU and our major operating subsidiaries to positive from stable.

Now, let me comment on economic conditions in our region.

As I have said in the past, I would characterize the local economy as generally better than the US, and I'm encouraged by various signs of improvement, particularly in the labor market, when compared to the US.

Since December, Connecticut's unemployment rate has decreased to 7% from 7.4%.

Massachusetts unemployment has dropped to 6.3% from 7.1% at year-end.

And New Hampshire's rate moved to 4.5%, from December's 5.2%, well below the current national rate of 6.7%.

These are the lowest unemployment rates we have seen in our region since 2009 for Connecticut and 2008 for New Hampshire and Massachusetts.

Also, construction employment remains very strong throughout our region, particularly in Connecticut, which has experienced a growth rate that is more than double the US average.

Now, I would like to provide you with a brief update on some current regulatory and legislative items.

First, of the regulatory front, we received the final decision from the Connecticut Public Utilities Regulatory Authority on March 12 regarding the approval for recovery of $365 million of storm costs over six years.

Recovery of these costs, together with a full cap cost of capital carrying charge, will begin on December 1. We will continue to earn no return on that deferred storm balance until December.

In a separate proceeding, we expect to notify PURA next week of our intent to file new distribution rights for CL&P next month.

It's actually a requirement of our Connecticut merger settlement agreement that requires us to file for new rates effective December 1, 2014.

We will ask for an increase that is essentially fully driven by our continued investment in CL&P's distribution system.

We've done a great job on merger savings as O&M Connecticut Light and Power is actually lower than it was a few years ago.

So, the rate increase is not driven by O&M, but rather, capital payments being made which contributed to our outstanding reliability results in 2013.

2013 was CL&P's best year since the year 2000.

Turning now to New Hampshire, on April 1, the New Hampshire PUC staff forwarded a report to New Hampshire's legislative oversight committee on electric utility restructuring containing an estimated valuation of PSNH's generating assets.

That estimated fair market valuation was about $225 million versus a book value of about $660 million.

As next steps, the report recommends three items: first that the commission complete the scrubber review before conducting any proceeding involving this divestitures; second, the legislature make the necessary statutory changes that would allow the commission to conduct a full review of our generating assets and to proceed with divestiture if it finds it is in the economic interest of PSNH's customers; and third, the commission requests ISO New England to conduct a study of the potential reliability and economic effects of the closure or retirement of our fossil generating plants.

We will work closely with the legislature and the commission, and we remain confident that our generation investment will be recovered in full, whether the assets are retained or divested.

In Massachusetts, there is a bill under consideration that would impact NSTAR Gas.

Legislators are considering a bill that we expect would spur oil to gas conversions in the state.

House and Senate versions of the bill were passed with minor differences that need to be reconciled in a joint conference.

The bill includes provisions that would reduce the timeframe from when a distribution company replaces infrastructure to when the cost of infrastructure is reflected in customer rates, thus providing the financial support for a sustained infrastructure replacement program.

It also includes a provision addressing gas expansion, allowing local distribution companies like NSTAR Gas to design and offer programs to customers, like areas zone charges, which increase the availability, affordability and feasibility of natural gas service to new customers.

We are hopeful this new legislation will pass later this year.

Also in Massachusetts, a new legislative proposal filed in February would require Massachusetts electric distribution companies like and NSTAR Electric and Western Mass Electric Company to seek long-term contracts for clean energy resources such as solar, wind and hydropower.

The proposal would require electric distribution companies to solicit proposals from developers for at least 18.9 million megawatt hours of electricity annually from clean energy generation sources including Canadian Hydro and allow companies to enter into 20- to 25-year contracts.

This bill is in its early stages of development, so it would be premature to predict its ultimate impact at this time, but it has a direct correlation to the regional energy market issue that I will discuss in a moment.

I should note, however, that we began contracting for renewable energy resources in conjunction with the Massachusetts Green Communities Act several years ago, and we continue to make progress on this effort.

In fact, the DPU approved in late February contracts that we have executed for wind power projects in New Hampshire and Maine as we continue to make progress toward the State's renewable portfolio targets.

At the federal level, there's nothing new to report on the complaint against the 11.14% base ROE that New England's transmission owners earned.

It is unclear when FERC will issue its decision.

We believe that the 100-basis point increase in the 10 year treasury rates over the past year have significantly mitigated our exposure in this docket.

We currently have about $2.3 billion of equity invested in our transmission, so a 10-basis point movement would equate to about two-thirds of $0.01 per share.

One more item I'd like to discuss relates to the current energy market in New England and the region's energy infrastructure.

Most of you know all too well the problem in our region -- the problem that our region faces with electricity generation capacity constraints in New England and our concerns about reliability and price.

Northeast Utilities is actively engaged in the New England governor's coordinated effort to invest in new gas pipeline and electric transmission infrastructure to meet the region's energy needs.

The regional energy infrastructure investment process is being driven by the governors in their state energy offices and supported by NESCO, which stands for New England States Committee on Electricity, and also ISO New England.

More than 4,000 megawatts of capacity is expected to retire over next five years, and in 2013, rising natural prices due to pipeline constraints pushed wholesale electricity prices up significantly.

With winter reliability and price volatility still fresh in our minds, and the retirement of the region's aging fleet in the foreground, our policy makers recognize that now is the time to invest in reliable, diverse, cleaner, and more affordable energy resources.

Through NESCO, the States have called for a 1,200 to 3,600 megawatts of new electric transmission and clean energy imports in the form of hydropower and/or wind.

The states recognize the opportunity that large-scale hydropower offers the region in stabilizing prices and helping advance their greenhouse gas reduction goals.

While NESCO is preparing for regional RFP process to expedite bringing these resources to market, state like Massachusetts are preparing for contracts by proposing legislation to allow participation in the regional procurement process and/or authorizing utilities to enter long-term contracts for hydro and wind to ensure that these clean energy resources actually come to market In April, the Massachusetts legislature held a hearing on the Patrick administration's proposed legislation that we continue to work with the legislature, the administration and other clean energy stakeholders to get an effective bill passed in 2014.

On the gas capacity for electric generation issue, we continue to have discussions with NESCO, our State leaders and other key stakeholders through the [neepole] process and how to bring additional natural gas pipeline capacity into the region to address our winter electric reliability and price volatility issues.

Through NESCO, the states have called for an additional 1 BCF of pipeline capacity in New England which includes between 300 million and 400 million cubic feet from the AIM project to meet our electric generation needs.

ISO New England and others have estimated a need in the range of 1 BCF to 2 BCF in addition to the current AIM project.

The NESCO proposal would seek a new tariff to allow ISO New England to collect pipeline costs from electric market participants since the natural gas is needed to keep the lights on.

The states have indicated a need to move quickly, and we anticipate that both infrastructure RFPs could be issued in the coming months.

Just last week, together with National Grid and United Illuminating, we provided NESCO with a proposed approach that would facilitate expansion of natural gas infrastructure into New England for generation use.

Obviously, this regional infrastructure initiative is ambitious and complex, but it is critically needed to address our customer's needs for reliable and affordable energy first and foremost.

These initiatives also provide opportunities for Northeast Utilities as a Company, given our experience in transmission, our relationship with Canadian Hydro generators, as well as our gas infrastructure assets and our work on gas expansion in Connecticut.

So, the industry is at a significant crossroad, and there is much more to come on these important developments.

That concludes my formal remarks, so I'll now turn the call over to Lee.

Thank you, Jim.

I will provide you with an update on our major capital projects and our natural gas expansion initiatives and then to the call back to Jeff for Q&As.

I will begin with transmission in our News family of projects.

You will recall that we finished the Greater Springfield Reliability Project last fall on schedule and about 6% under budget.

We commenced construction of our interstate reliability project in March after receiving all required permits.

We will build the approximately 40 mile Connecticut section of the project and National Grid will build the Rhode Island and Massachusetts sections.

Our section is estimated to cost about $218 million and should be completed in the fall of 2015.

The only outstanding permit remaining on the National Grid section is from the Massachusetts Energy Facility Siting Board, or EFSP.

And earlier this year, EFSP board members unanimously directed staff to prepare and order improvement projects.

We expect EFSP approval to be finalized soon after that, and all sections of the project will be completed by the end of 2015.

Turning now to the Greater Hartford Central Connecticut Liability Project, we expect that ISO New England will identify a series of solutions the summer to remedy current and future overload and local conditions that exist today or will emerge in the near future across Central and Western Connecticut.

We expect to invest about $300 million in those solutions, and we will be able to provide you with a more definitive figure once ISO New England identifies the necessary grid enhancements.

Turning to Northern Pass, US Department of Energy continues to work on its draft environmental impact statement.

Earlier this year, DOE indicated that its draft EIS will cover not only our recommendations of the route, but various potential alternative sections.

The DOE recently released a summary of the comments it has received on the project and has released its list of alternative routes it has identified for analysis in the draft.

We support looking at alternative sections of the route and are pleased DOE is looking at these alternatives at this time.

DOE has posted a target date of December 2014 on its website to issue its draft EIS.

Once it is issued, DOE will accept public comments before issuing a final EIS.

Once we receive the draft EIS, we will be in a position to file our application with the New Hampshire Site Evaluation Committee.

We continue to expect final approval of the project in 2015 and a completion in the second half of 2017.

Earlier, Jim discussed the NESCO RFP process.

I will add some color around it.

New England has become increasingly dependent on natural gas generation which now accounts for just over half of all electricity consumed in the region.

That is likely to increase after the retirements of Vermont Yankee nuclear plant and the Salem Harbor coal units later this year.

But when temperatures plunge as we saw this winter, more natural gas is consumed to keep the region's homes and businesses and [lessons] available around the region's generator.

As a result, we operated units that are older and less efficient and which also burn more costly oil and imported LNG to keep New England's lights on.

That drives up prices.

The average spot market wholesale price at the New England hub was nearly $0.17 a kilowatt hour in January of 2014 and nearly $0.15 a kilowatt hour in February.

Average February wholesale prices were up 41% from February 2013.

Even in March, normally more of shoulder month, wholesale prices were just over $0.11 a kilowatt hour, compared with $0.053 in March of 2013 and $0.026 in the very mild March 2012.

Additionally, there were times this winter when ISO was concerned that they would be unable to supply enough power to meet the region's needs and would be forced to shut off load.

To put this in context, the wholesale electricity market in New England from December through March this past winter was $6.8 billion.

During the same four months of the winter of 2012 to 2013 it was $3.6 billion; during the same four months of 2011 to 2012 it was a $1.6 billion market.

Clearly, we are entering new territory in terms of the cost to New England electric customers which will need to -- which customers will need to bear in future winters.

There is no question that the region needs significant new supplies to help tame the explosive growth in winter energy costs, and there is also no question that Northern Pass is a crucial component in meeting our energy challenges later this decade.

Hydro Quebec was a key supplier of electric power to New England this winter and can further expand exports if it has additional transmission access into the region.

Our Northern Pass team in New Hampshire continues its outreach to communities, including residents living along the proposed route.

We are working with business leaders and other stakeholders to further explain the facts surrounding the project and the significant benefits it will provide to New Hampshire and the region.

We believe that Northern Pass is the single best positioned electric transmission project to address New England's energy challenges.

First, it is at least three years ahead of any of the project that could add meaningful electric transmission and generation capacity to New England.

Next, it can be located on a route that requires no additional property acquisition.

It has FERC approval and has already passed the ISO New England customers safe and reliable interconnection to the grid.

That ISO sign off was the culmination of the more than a three-year review process.

And perhaps most importantly, we have the supplier on the other end of the line in the form of Hydro Quebec that is willing to construct new transmission in Canada and to connect our line and has adequate generating capacity to fill the line with power for New England throughout the year.

We believe this past winter's appearance has increased support for Northern Pass significantly.

Of course, our transmission development programs involve much more than the news in Northern Pass.

As I mentioned during the analyst day, we have many smaller reliability transmission projects we continue to execute in all three states.

In the first quarter of 2014, our transmission capital expenditures totaled approximately $90 million, and we continue to project approximately $660 million of transmission CapEx in 2014.

Moving on to generation, PS&H's units performed extremely well in the first quarter and provided a critical source non-natural gas fired generation for New Hampshire.

Our generation fleet produced 10% more power than it did in the first quarter of 2013 and 63% more than in the mild first quarter of 2012.

In Massachusetts, over the past week our third and largest solar site at Western Mass Electric commenced commercial operation.

We now have 8 megawatts of solar at OneCo producing more energy than we had initially projected and at a much lower cost than our initial estimates.

Our solar development program has also turned two brownfield sites and one landfill site into important assets for Springfield and Pittsfield, Massachusetts.

We continue to earn a fully tracked return in our approximately $35 million investment in those facilities.

Moving on to natural gas, as Jim noted our very strong sales this past winter.

In fact, the first quarter of 2014, Yankee Gas recorded 7 of its top 10 highest send out days ever, and NSTAR Gas experienced 2 of its top 10 send out days ever.

All of Yankee Gas's top 5 send out days, as well NSTAR Gas's top send out day occurred this year.

This occurred not only due to cold weather, but also due to each company's increased customer count.

In the first quarter, we added nearly 2,200 new space heating customers and continue to expect to add about 10,000 new customers this year.

Finally, I should note that despite the cold and snowy winter, our electric service reliability was very good in the first quarter.

This continued and strong performance we had in 2013, which was NU's best ever from a reliability standpoint.

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

And I'm going to turn the call over to Christine to remind you how to enter questions.

Christine?

Yes, thank you.

(Operator instructions)

Thank you, Christine.

Our first questioner today is Dan Eggers from Credit Suisse.

Good morning, Dan.

Good morning, guys.

Could you maybe put a little more context, obviously with the volatility of this quarter there is a big draw on the system.

What affect did that have in the conversations with some of your constituents on Northern Pass?

And did that change the tone with the people who have been maybe more difficult in the process so far?

Hello, Dan, this Lee Olivier.

I think this past winter has changed people's attitudes about the project in New Hampshire significantly.

I think there is a real view that the project is needed.

I think even many of the opponents would agree the project is needed.

The real question is, what further do we need to do around mitigation to ensure that we build as broad a consensus as we can around the project as we go into the site process in New Hampshire.

If you look at the project, it is very, very strong support from labor, and strong support from business.

A growing support from key legislators in New Hampshire and also people from the northern part of New Hampshire were the project has been most controversial.

As I have said in my remarks, our teams continue to work with all of those constituencies to build this broad coalition, and that should come together later this year in a way that is more obvious and more vocal.

Okay.

Then one of the growth opportunities has been or targeted to be conversion of the heating use customers to natural gas.

Was there any conversation given some of the deliverability issues this winter, either A, should we change trajectory of moving to gas until we make sure we have supply?

Or B, is there a greater push to figure out other infrastructure needs to make sure utilities have more gas available, even for extreme periods like this winter?

I think Jim commented on the series of new gas pipelines that have essentially been approved the AIM project, and there is a smaller Tennessee gas pipeline project.

But these projects will come in into service around November of 2016, so there is ample supply in the pipelines to support our conversion estimates as we go forward through that period of time.

And of course, once those upgrades to existing pipelines are complete, that will provide a little extra margin for generators.

But to the point that NESCO is making, there will need to be a larger gas pipelines brought into the region.

The region probably needs another 1.5 to 2 BCF of gas, either in LNG storage or pipelines.

Okay, so anything about that being in November of 2016, what strategies are you guys going to deploy for this next winter before the infrastructure gets put in place?

Are you talking about strategies for our EDC -- our LDC?

I guess probably from a gas supply perspective or from a regional perspective, both for gas and electric.

Are there things that you guys can adjust for the 2014, 2015 winter having seen what happened in 2013, 2014, both operationally or investment-wise to make some fixes?

Yes, I think from the LDC standpoint, we're got the gas that we need, that's not going to be an issue, we can meet our expansion plan.

The real question is what does the region do around ensuring it has sufficient electrical capacity.

As you know, last year ISO New England put in place, say, over 3 million barrel of oil program that was directly subsidized.

They are currently looking at what would be another program that would provide similar benefits in terms of reliability and sufficient capacity.

And of course, the [dilemmas] have said before is the we had the Vermont Yankee plant and also this [Shun harbor] plant which will not be in service.

They operated well, they can provide about 2.5 million megawatt hours through the winter period.

So, what that tees up is a somewhat precarious position this coming winter.

Not around getting gas to our LDC customers, but ensuring the liability on our grid.

And that is something that we, NU, are working very closely with ISO New England and along with other major utilities in the region.

This is Jim.

I'd only add, the other thing that Northeast Utility specifically can do is to make sure that our generating fleet in New Hampshire is available and ready to be dispatched if the ISO needs it during the winter next year.

Okay thank you, guys.

Thanks, Dan.

The next question is from Travis Miller from MorningStar.

Good morning, Travis.

Good morning, thanks.

Wondering, back on this whole gas pipeline, would you guys be interested in taking stakes and helping construct interstate pipelines?

The utilities national grid, Northeast Utilities and UIL have submitted suggestions in terms of the solution here.

That solution would have the electric distribution companies recover a FERC approved tariff from electric retail customers in New England.

In order to do that, the EDCs would need to be appropriately compensated for entering into these long-term contract commitments and for lending financial stability in the form of our balance sheets and credit ratings.

So, this compensation could be in the form of equity participation in the project and/or other compensation for lending credit quality.

And that would be a rated-based type of compensation, is that how the economics will work?

It's still to be defined in terms of the structure, but I think we recognize that if we are going to use our balance sheet and credit rating qualifications, adding these contracts puts pressure on the companies, certainly from a credit rating perspective, and some remuneration would be positive.

So, that would be appropriate.

It is still to be defined, Travis, but that's the position of the utilities.

Okay.

And then real quick on the transmission business, what would have been the core impact if you backed out that tax impact?

Just approximately $0.02.

Growth?

Okay, thank you.

All right, thank you, Travis.

Next question is from Julian Dumoulin-Smith from UBS.

Hello, good morning.

Perhaps, again, not to beat a dead horse, but this is a pretty complex subject.

Going back first on the gas infrastructure side, what is the opportunity if you can bucket it out intra regionally and then from an interregional perspective, I suppose there is a discussion amongst folks to have a tariff that would be a backstop on the electric side of the bill.

Is that something that is palatable to you?

Or ultimately do think that this is going to end up going back and being something that gets billed directly to you and you end up being the backstop for a contract?

It's a little bit two-part question there.

I will just answer the first part in terms of the infrastructure.

There is about four pipelines that run into New England.

The most valuable pipelines, obviously the Algonquin pipeline, Spectra and the Tennessee pipeline's Kinder Morgan.

They come in from the West, and so they interconnect through New York into Marsalis.

Ideally, what you would want to have is upgrades in one or both of those pipelines and/or some additional LNG facilities.

Because I think you look out the future, if you've got about 52% of the energy in New England right now with this coming off of natural gas, and if you factor in approximately 8,000 to 9,000 megawatts of returns (inaudible) and you look up what's going to repower that, most of that is almost all going to be gas.

In the future, you are looking at probably 80% of the energy in the region during peak periods coming from natural gas.

So, that's what that you'll need to feeling robust, both intra region and inter region series of upgrades.

With that, I will let Jimmy pick up the tariff issue and how contracts are being administered.

Sure.

Fundamentally, Julien, as you know that the LDCs have contracted for supply, adequate supply to meet their home heating customers' load.

The issue here is that the gas generators have not subscribed to long-term capacity needs.

The fact that they are not able and not willing to step up to contract for it, the utilities are a natural solution because at the end of the day, it is the utility customers that are bearing the brunt of this volatile gas market in the winter.

So, I think it makes sense for utilities to collectively support contract, have equity positions in a new supply into the region to basically dampen that volatility that has the generators experience.

And those costs can be spread around to electric customers throughout the region, all of whom benefit directly from that investment.

Great.

And then moving over to the transmission side of the equation here, as far as solutions, for MPTU, you just talked about alternative routes.

What does that mean from a cost and from a timeline perspective for the project?

Does that mean you still expect to move forward with the draft EIS at the same kind of time like we've talked about before?

There is a number of options there, some of them would consider rearranging right away.

Some of them would consider doing undergrounding in various environmentally sensitive areas.

However, none of the options as currently laid out would impact our schedule, so we think the schedule is fine.

To the point of cost, obviously if you do undergrounding, more undergrounding, right now we're doing eight miles of undergrounding.

To the extent that you do more, the project would cost more.

Well, perhaps just as a follow-up, when do you think we would hear about those updates, if you will?

Or when does BOE need to make a decision on putting forth the best alternative route, or what have you?

That will be when they issue their draft EIS in December of this year.

And with that, presumably we will get something of a better estimate of what the new cost might be?

We will be preparing -- along with that, we will be preparing a cost estimate when we filed with SEC in early next year.

Great, thank you very much.

Good luck.

Thanks, Julian.

Next question is from Michael Lapides from Goldman.

Good morning, guys, and congrats on a good quarter.

A couple of things, and Jim, I apologize because your prepared remarks on some of the legislative staff, I'm not sure I fully caught all of that.

Can you give us an update on the Massachusetts legislation, both pieces?

So, the gas related one, and when you talk about that one, can you talk about what it means for either rate base or the potential change in natural gas LDC demand in Massachusetts?

And can you also talk about the renewable one?

Is there any impact on you besides what it could mean for contracting Northern Pass?

Sure.

On the gas side, the pieces of legislation that are in conference and address infrastructure investments to basically reduce gas leakage to upgrade the system overall, that is likely to involve some sort of timely cost recovery, think of it as a tracker.

And the other part of the legislation is intended to encourage and enable more conversions from home heating oil to gas.

So, the House and the Senate versions are in a conference and being reconciled currently.

The other piece of legislation which is enact relative to clean energy is a recognition that in order to commit to this NESCO process or even outside of the NESCO process, there needs to be an enabling legislation that would allow utilities to contract for a number that is in excess of 18 terawatt hours of renewable supply, basically to the north, wind and hydro.

So, two pieces of legislation that we are watching closely that, I think both of which have positive impacts on the Company's prospects.

And the gas one, or the two natural gas related ones, I understand they're different pieces in Massachusetts.

When they come together in conference, it's conceivable that the end product to end impact for your Company will look something a little bit similar to what happened in Connecticut last year.

It may, although I might say, Michael, the prospects, I think are less.

In Connecticut, we had an extremely low gas penetration rate, 32% whereas the Massachusetts penetration rate is closer to 50%.

I would say that the opportunity, the prospect for our new customer conversions probably would not be as aggressive as we saw in Connecticut.

Got it, okay.

And you talked a little bit about O&M on the quarter, Can you walk us through the components?

When you think about the year-over-year changes in O&M that are embedded in guidance, what is pension related?

What is removal of nonrecurring items, storms or other, that happened in 2013?

And what is really tied to savings you are driving from merger synergy savings?

Sure.

The guidance that we have given the Street for this year is a 4% reduction in O&M and 3% to 4% reduction long term through 2017.

What we experienced this year, when you do a comparison with the first quarter of 2013, the major drivers were our pension expense is lower and our storm costs were lower.

We had a pretty good quarter in terms of very little storm expenses whereas a year ago, there were -- it was a wintry winter, basically.

So, those are the two major drivers.

What I will tell you that what was experienced for O&M to date is very much in line with our internal budget.

So, the first-quarter results from an O&M perspective, pretty much spot on.

Obviously, we were pleasantly surprised by the top line growth, the sales growth that we did experience.

Got it, okay, Jim.

Thank you very much.

Much appreciated.

Thanks, Michael.

Next question is from Paul Patterson from Glenrock.

Good morning.

Hey, Paul.

Hey.

Just back on the gas infrastructure situation.

How do we think about this, the competing issue of having the utility enter into obligations for gas, for electric power versus these other discussions?

About having the forward capacity auctions that have more commitment required for capacity providers instead and having the wholesale market drive the need for new gas pipelines?

How should we think about those two things?

I think there's a recognition that the markets don't seem to be generating the investment that is needed and is in the customers best interest.

There have been instances in the past, as you now Paul, where there has to be interventions in the markets when we have significant irregularities.

Must run contracts is probably the most classic example.

Here, I think, without some sort of intervention, we don't anticipate that these pipelines will be built on spec.

We don't see the generator stepping up to make the long-term commitment.

To the extent that we have reliability concerns, that we have economic concerns, it is in the interest of our consumers for somebody else to intervene to deal with the irregularities in the market today.

And I would just add into that, the generators are built for the generators.

They all have different economic interest.

Obviously, if you're a nuclear generator, you don't particularly care where the gas supply is because the less gas, the higher the price is in imported LNG and your margins go up pretty dramatically.

There are other generators that have some storage, hydro and so forth.

All of those kinds of assets are optimized when gas prices are very, very high.

It's unlikely that the market will solve this.

Now, if the ISO rules that they proposed go through, that would be in the 2018, 2019 timeframe, and there is significant penalties on generators that don't show up on a shot fall day, then that could cause a fair number of those to exit the market, as we would expect they to do.

And that means there would be a fairly significant impact on the capacity market in terms of the new supply and demand curve that ISO has also filed at FERC.

There will be a shakeout there with the non-nuclear generation capacity over the course of the next seven or eight years.

The only thing I would add as well is the sense of urgency is a very real, I think, and palpable.

Energy Secretary [Monez] was here last week and held a conference where this issue or this concern was front and center.

In fact, Tom May, CEO, was on one of the panels that were on the agenda that day.

The concern is there, and I think we need a timely solution to resolve the problems as quickly as we can.

Okay, when do we see a more formulated?

Because as you know, there are arguments and stuff that are being raised.

What is the timeline we should be looking for in terms of the NESCO proposal, other proposals being -- going through the regulatory -- going through the process by which we see the actual policy codify, if you know what I'm saying?

We think that -- the sooner the better.

We think a timeline that would involve an RFP process this summer into this fall and decisions being made, because when you back off -- when you take a look at what the siting requirements are, you go through a process, you select a project, the project needs to be cited.

Several regulatory approvals involved there.

Then you begin construction.

I think if you began the process now, you are still looking for a solution that is out in the winter of 2017, 2018.

So, I think we would hope for a fast-track approach to this effort.

Okay, and then just finally, circling back to New Hampshire, and you guys did mention, obviously this would bode well for your arguments for Northern Pass and I would assume to be for the coal plant there as well.

Is that actually what is happening on the ground?

Are people actually seeing this polar vortex stuff?

Has that changed some people's minds?

Or just you guys on the ground, what is your experience in terms of how people have actually who are in the decision-making process seeing these projects, or seeing these assets or potential assets versus the -- has there been a change politically on the ground as a result of this, or?

I think there is a significant change.

In New Hampshire, still has some level of pulp and paper process mills.

During the winter time, many of those were shut down because they run off gas for the process, because there was no gas.

So, there were a considerable amounts of layoffs during the period.

I think even the folks that look at the PSNH assets that we currently own which performed extremely well, they understand.

They're old assets, they're not going to be around forever.

And we need replacement power that is firm, that is clean, that is long-lived and that is not subject to a lot of the technological issues that other power sources have.

So, there is a sense that we need to have it for the security of the state, for the economic development of the state.

Jim mentioned the unemployment rate is very low.

There are some other major manufacturers that would like to move into New Hampshire, but they have a current concern around the availability of energy and the price of energy.

And so I think what this has done is galvanized the business community, elected leaders.

We have always had labor there, but it's also getting the opponents to rethink their position.

Their position in many cases is, well, it's no longer -- we're not going to support PT ever.

It's what's the best way to get the project built with the least impact on New Hampshire?

That's kind of the dialogue that is taking place throughout much of New Hampshire and with key stakeholders in New Hampshire.

Great, thanks for the color.

Thank you, Paul.

Next question is from Rajeev Lalwani from Morgan Stanley.

Good morning, John.

Two quick questions, one on the NESCO process.

Do you know if the states are choosing between two alternatives?

One being more pipeline capacity and the other being RFPs for generation and transmission?

Then the second question, I don't think you touched on this in your prepared remarks, if you did, I apologize.

But the New Hampshire legislation around undergrounding, some color there would be great as well.

Sure.

On the first question, both on transmission and energy RFP and a gas pipeline RFP are being considered, basically in the same conversations, even though the saw different solutions -- different problems, rather.

And in New Hampshire, there is periodic legislation.

Some of the being considered that would rely -- would require more undergrounding is some legislation looking for stricter siting requirements, mandatory use of state transmission corridors.

The -- there have been various pieces of legislation, none of which have been enacted to date.

Great, thank you.

Thanks.

The next question is from Kit Konolige from BGC.

Good morning, Kit.

Good morning, guys.

Two follow-up questions.

I may have missed this, but did you talk about -- I see that on a weather adjusted basis, gas sales were quite strong in the first quarter.

Can you just give us a little insight into that?

Sure, Kit.

We were -- weather adjusted, our gas sales were up 3.6%, which is very much in line with the guidance that we have given.

We think that our gas sales will be 3% to 4% going forward, and we continue to be on track in terms of the gas conversion targets that we've established.

We have increased customer count, I think we added to 2,200 customers here in the first quarter.

The 3.6% weather adjusted is spot on with where we expected to be.

Very good.

And to follow on Northern Pass one more time, in your prior discussion of, if I can call it the possibility of some further adjustments such as undergrounding and so on, if -- in going back and forth with all of the other parties that are interested here, previously you just submitted a new plan with new adjustments.

Should we be looking for any kind of settlement with other parties signing on to something you filed the next time?

Or will this just be an iterative process where you might take in comments and adjust your plans and draw new blueprints and go from there?

What -- are there any landmarks or any meetings or any timelines that we can expect for a different kind of Northern Pass eventually?

Yes, Kit, this is Lee.

I think I would just summarize it as, we are in conversations with many, if not all of the folks, that you mentioned.

The coalition that you would need to get a consensus.

I think it's too early to say right now that we are going to have a big news conference here or whatever in June or July and say we have a coalition.

The coalition supports the project.

We know we have the makeup the coalition has discussed.

Labor, we expect to see major labor support, business support, elected leaders support.

The environmental folks are the folks that we're having considerable dialogue with.

Will you ever be able to get all of that environmental groups?

No.

But we hope to get sufficient support around mitigation that we would propose later in the year.

So I think that because of what has happened in the winter, there's a growing consensus that we need to pull together as a state and as a region around a solution for the project.

And so later this year, we will be able to provide you with better insight in where we are on that.

Great, very helpful, thank you.

Thank you, Kit.

We don't have any more questioners, so we want to thank you for joining us today.

If you have any further questions, please call John or myself later in the day.

Have a great weekend.

Thank you, and thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.