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Northeast Utilities System (NYSE:NU)

Q1 2014 Earnings Conference Call

May 2, 2014 9:00 AM ET

Executives

Jeffrey R. Kotkin – Vice President of Investor Relations

James J. Judge – Executive Vice President and Chief Financial Officer

Leon J. Olivier – Executive Vice President and Chief Operating Officer

James A. Muntz – President of Transmission Business

Philip J. Lembo – Treasurer and Vice President

Jay S. Buth – Chief Accounting officer, Vice President and Controller

John Moreira – Director of Corporate Financial Forecasting and Investor Relations

Analysts

Dan L. Eggers – Credit Suisse Securities (NYSE:USA) LLC

Travis Miller – Morningstar Research

Julien Dumoulin-Smith – UBS

Michael J. Lapides – Goldman Sachs & Co.

Paul Patterson – Glenrock Associates LLC

Rajeev Lalwani – Morgan Stanley & Co. LLC

Kit Konolige – BGC Partners LP

Operator

Welcome to the Northeast Utilities Earnings Call. My name is Christine and I will be the operator for today's call. (Operator Instructions) Please note that this conference is being recorded.

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

Jeffrey R. Kotkin

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, NU Executive Vice President and Chief Financial Officer; and Lee Olivier, our Executive Vice President and Chief Operating Officer.

Also joining us today are Jim Muntz, 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 U.S. Private Securities Litigation Reform Act of 1995.

These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release we 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 10-K 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 10-K.

Now, I will turn over the call over to Jim.

James J. Judge

Thank you, 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 highlights of economic conditions in our region. And I conclude with an update on various regulatory proceedings and legislative activity impacting our companies.

You probably saw our first quarter earnings release that was issued by yesterday. We earned $241.8 million or $0.76 per share on a recurring basis this quarter, compared $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.

So we’re off to a good start for the year and feel comfortable with the full year earnings per share guidance of $2.60 and $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 Northeast Utilities from other investment opportunities in our sector.

As you might have expected a major factor in the quarter 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 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 a recent favorable economic data in our region, which I will discuss later. Another positive driver was decrease in operations and maintenance costs that had an earnings impact during the first quarter of this year which improved earnings per share $0.02 for the quarter. The two biggest drivers there, while lower pension benefit costs, which we discussed during on Analyst Day as being a significant driver of lower O&M for the next two years. And our reduction in storm cost.

You may recall that last year we incur significant storm cost is result of wintry weather. All most of these cots were deferred some or not. So storm costs that effected first earnings were lower as compared to 2013 first quarter levels. While storm costs can vary with 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 close two years ago, we have doubled the number customers who receive electronic bills, achieving top quartile performance for each operating company and saving more than a million dollars annually on postage expenses. A small success story that we’re quite proud of an example of our focus on adopting best practices post merger.

Let me remind you that our guidance calls for 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 2013s 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 parent and other. As a result in 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 increasing depreciation in property taxes reduce the quarter’s results by $0.02 compared to last year. And it’s reflection of the continued investments in our system infrastructure. While interest expense was not a major positive driver in our earnings performance for the quarter, we continued to take steps to walk in low interest costs to some recent successful financing activity.

In January Yankee Gas issued a $100 million of third 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 and 7, 8s 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 is outlook on NU in our major operating subsidiaries so positive from stable.

Now let me comment on economic conditions in our region. As I said in the past, I would characterize our local economy as generally better than the U.S., and I'm encouraged by various signs of improvement particularly in the labor market when compared to U.S.

Since December, Connecticut its 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 the 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 in growth rate that is more than double the U.S. average.

Now I would like to provide you with a brief update on some current regulatory and legislative items. First on the regulatory front we received the final decision from the Connecticut public utility 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 the full cost of capital recurring charge will begin on December 1st. 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 intent to file new distribution rates for CL&P next month. It's actually 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 contributor 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 $225 million versus a book value of about $660 million.

As next steps, the report recommends three items. First that the commission completes the scrubber review before conducting any proceeding involving divestiture. Second the legislature makes 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 CL&P'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 year 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 screen 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.

This is unclear when FERC will issue its decision. We believe that the 100 basis point increased 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 system, so a 10 basis point movement would equate to about two-thirds of $0.001 per share.

One more item I would like to discuss relates to the current energy market in New England of the regions energy infrastructure. Most of you know all too well the problem in our region – the problems 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 infrastructure investment process is being driven by the governors and the state energy offices and supported by NESCO, which stands for New England State's 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 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 the 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 peephole 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 from 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 3 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.

Leon J. Olivier

Thank you, Jim. I will provide you with an update on our major capital projects and our natural gas expansion initiatives and then turn the call back to Jeff for Q&A’s. I will begin with transmission and our newest 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 $280 million and should be completed in the fall of 2013.

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 in order improvement projects. We expect the FSP approval to be finalized soon after that and all sections of the project will be completed by the end of 2013.

Turning now to the Greater Hartford Central Connecticut Liability Project, we expect that ISO New England will identify a series of solutions this 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, U.S. 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.

In 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 of it’s 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 completion in the second half of 2017.

Earlier, Jim discussed the NESCO 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 [indiscernible] available around the region's generator.

As a result, we operated units that are older and less efficient, which also burn more costly oil and imported L&G 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 $5.03 in March of 2013 and $2.06 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 2012 to 2013 it was $3.6 billion; during the same four months of 2011 to 2012 it was $1.6 billion market.

Clearly, we are entering new territory in terms cost to New England electric customers which will need – 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 test for safe and reliable interconnection to the grid. That ISO sign off was the combination of the more 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, excuse me in Canada and to connect our line and has adequate generated 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 2014 our transmission capital expenditures total approximately $90 million and we continue to project approximately $660 million of transmission CapEx in 2014.

Moving onto generation PSNH unit performed strong extremely well in the first quarter and provided a critical stores of non-natural gas fired generation for New Hampshire. Our generation fleet 10% more power that it did in the first quarter of 2013 and 63% more than it did 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 WMECO producing more energy then we had initially projected and at a much lower cost in our initial estimates. Our solar development program is also current 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 onto 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 sent out days ever. All of the Yankee gas is top 5 send out days as well as NSTAR gas is top send out day correct this year. This occurred not only due to clod weather, but also due to each company 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 Jeff.

Jeffrey R. Kotkin

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

Question-and-Answer session

Christine

Yes, thank you. We will now begin the question-and-answer session. (Operator Instructions).

Jeffrey R. Kotkin

Thank you, Christine. Our first questioner today is Dan Eggers from Credit Suisse. Good morning, Dan.

Dan L. Eggers – Credit Suisse Securities (USA) LLC

Hey, 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?

Leon J. Olivier

Hi, Dan. This is Lee Olivier. I think this past winter has changed people's attitudes around the project and New Hampshire significantly. I think there is a real view that the project is needed. I think even many of the opponents would agree that the project is needed. So the real question is what further do we need to do around mitigation to ensure that we build as broader consensus as we can around the project as we go into deciding process in New Hampshire.

So we look at the project it is very, very strong support from labor and strong support from business, growing support from key legislators in New Hampshire and also people from the northern part of New Hampshire where the project has been most controversial. So as I have said in my remarks, our teams continued 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 appropriate.

Dan L. Eggers – Credit Suisse Securities (USA) LLC

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?

Leon J. Olivier

Yes, I think Jim commented on the series of gas pipelines that have essentially been approved the aim project and then there is a smaller Tennessee gas pipeline project. But these projects will come into service around the 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 the existing pipelines are complete, that will provide a little extra margin for generators. But to the point that NESCO was making, there will need to be a larger gas pipeline spread into region, the region probably needs another 1.5 BCF to 2 BCF of gas either in LNG storage or pipelines.

Dan L. Eggers – Credit Suisse Securities (USA) LLC

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?

Leon J. Olivier

Well. Are you talking about strategies for our EDC – our LDC?

Dan L. Eggers – Credit Suisse Securities (USA) LLC

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?

Leon J. Olivier

Yes. I think from the LDC standpoint we've 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 that it has sufficient electrical capacity and as you know last year ISO New England put in place over $3 million barrel of oil program of that was directly subsidized.

They are currently looking at what would be another program that would provide similar benefits in terms of the reliability and sufficient capacity, and course the dilemma as I have said before, is that we have the Vermont Yankee you plan and also the Salem Harbor plant which will not be service, they operate it 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 of LDC customers, but ensuring the reliability on our grid and that’s something that we in NU are working very closely with ISO New England and along with the other major utilities in the region.

James J. Judge

This is Jim. I would only add other thing that Northeast Utilities specifically can do is to make sure that are generating fleet in New Hampshire is available and ready to be dispatched if the ISO need to during the winter next year.

Dan L. Eggers – Credit Suisse Securities (USA) LLC

Okay. Thank you, guys.

Jeffrey R. Kotkin

All right. Thanks, Dan. Next question is from Travis Miller from MorningStar. Good morning Travis.

Travis Miller Morningstar Research

Hi good morning thanks. I’m wondering back on this will gas pipeline, would you guys be interested in taking stakes and helping construct interstate pipelines?

Leon J. Olivier

National grid Northeast Utilities and UIL have submitted suggestions in terms of the solution here. That solution would have the other two distribution companies recover a FERC approved tariff from electric retail customers in New England. In order to do that the EDC's would need to be appropriately compensated for entering into these long-term contract commitments and for lending financial stability in the form of 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.

Travis Miller Morningstar Research

And that would be a rate based type of compensation, is that how that economics would work?

Leon J. Olivier

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 company's certainly, credit rating perspective and some remuneration would be positive. So that would be appropriate. So it still to be defined Travis but that's the position of the utilities.

Travis Miller Morningstar Research

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

Leon J. Olivier

Approximately $0.02.

Travis Miller Morningstar Research

Throughout. Okay. Okay thank you.

Jeffrey R. Kotkin

All right. Thank you Travis. Next question is from Julien Dumoulin-Smith from UBS. Good morning Julien.

Julien Dumoulin-Smith – UBS

His good morning. So 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 kind of bucket it out intraregional and then from a interregional perspective, I suppose there is a discussion amongst folks to have a tariff that would be a backstop on electric side of the bill. Is that something that’s palatable to are 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 back stop for contracts? So it’s a little bit – two part question there.

Leon J. Olivier

I’ll just answer the first part in terms of the infrastructure, there is about four pipelines that run into New England, the most valuable pipeline is obviously the Algonquin pipeline, Spectra and Tennessee pipelines, Kinder Morgan and they come in from the west. Again, so they interconnect through the article or into Marcellus. So ideally which we would want to have is upgrades in one or both of those pipelines and/or some additional LNG facilities. If you look of the future you have about 52% of the energy New England right now that’s coming of natural gas and if you factor in approximately 8,000 to 9,000 megawatts of retirements and you look at out what’s going to recover that most of that almost power than the gas.

So in the future you are looking on probably 80% of the energy in the region during the periods coming from natural gas. So that’s so that you need fairly robust of inter region series of upgrades. With that I will let you may pick up the tariff issues and how contracts of administered.

James J. Judge

Sure and fundamentally Julie 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 sort of subscribe to long term capacity need. So the fact that they are not aid but not willing to step up to some of contract for it. The utilities are natural solution because at the end of the day it’s the utility customers that are bearing the brunt of this volatile gas market in the winter. So I think it make sense for utilities to collectively support contract have equity positions in a new supply into the region to basically dampen that volatility to generate is experience and those costs can be spread around to electric customers throughout the region all of whom benefit directly from that investor.

Julien Dumoulin-Smith – UBS

Great and then moving over to the transmission side of the equation here, as far as solution. For MTU just talked about alternative route, what is that mean from a cost and from that time line perspective for the project just that mean you still expect to move forward with the draft DIS at the same kind of time line we talked about before.

Leon J. Olivier

There is a number of options there some of them with consider you know rearranging right away some them would consider doing under grounding and various environmentally since it is various. However none of the options is currently laid out with impact our schedule so the impact schedule is fine to the point of cost obviously if you do under grounding more under grounding right now we doing eight miles of under grounding to the extent that should be more the project would hear about those updates if you will? When the BOE need to make a decision on putting forth a best alternative route to what have you?

James J. Judge

That will be when they issued the draft EIS in December of this year.

Julien Dumoulin-Smith – UBS

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

James J. Judge

We will be preparing along with that we will be appearing cost estimate when we filed with the SEC in early next year.

Julien Dumoulin-Smith – UBS

Great. Thank you very much.

Jeffrey R. Kotkin

Thanks, Julien. Our next question is from Michael Lapides from Goldman. Good morning, Michael.

Michael J. Lapides – Goldman Sachs & Co.

Hey, good morning, guys. Congrats on a good quarter. Couple of things and Jim I apologize because in your prepared remarks on some of the legislative staff, a mature fully caught all that. Can you give us some 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 based or the potential change in natural gas LBC demand in Massachusetts? And can you also talk about the renewable one. Is there any impact on any besides what I could in for contracting Northern Pass?

James J. Judge

Sure, on the gas side, the pieces of legislation that are in conference address infrastructure investments. So, basically reduce gas leakage to upgrade the system overall, but is likely to involve some sort of, timely costs recovery in any can think of 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 Senate versions are in conference and being reconciled currently. The other piece of legislation, which is relative to clean energy is recognition that in order to commit to this NESCO process or even outside of the NESCO process, there needs to be enabling legislation that would allow utilities to contract for a number that is in excess of 18 kilowatt hours of renewable supply basically to the North wind and hydro. So, two pieces of legislation that we are watching closely than I think both of which have positive impacts on the company’s prospects.

Michael J. Lapides – Goldman Sachs & Co.

In the gas one other to natural gas related ones I understand the different pieces in Massachusetts, kind of when they come together conference it's conceivable that the ends product, and impact for your company will look something little bit similar to what happened in Connecticut last year?

James J. Judge

In May, although I would say Michael that the prospects I think are less. I mean in Connecticut we had an extremely low gas penetration rate 32% whereas the Massachusetts penetrations rates closer to 50%. So I would say that the opportunity of the prospects for new customer conversions probably would not be as aggressive as we saw in Connecticut.

Michael J. Lapides – Goldman Sachs & Co.

Got it. Okay. You talked a little bit about O&M on the quarter can you walk us through components when you speak about the year-over-year changes in O&M that are embedded in guidance? What’s pension related? What’s kind of removal of non recurring items storms or other that happened in 2013? And what’s really tied to kind of savings you are driving from kind of merger synergy savings?

James J. Judge

Sure. The guidance that we have given to street for this year is a 4% reduction in O&M and 3% to 4% reduction long-term for 2017. So what we experienced this year we do a comparison with the first quarter of 2013 the major drivers were pension expense is lower and our storm costs per lower. We had a pretty good quarter in terms of very little storm expenses where as year ago there were its 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 inline with our internal budget. So the first quarter results from O&M perspective pretty much spot on. Obviously we’re positively surprised by the top line growth, the sales growth that we did experience.

Michael J. Lapides – Goldman Sachs & Co.

Got it okay Jim. Thank you very much. Much appreciated.

James J. Judge

Thank you.

Jeffrey R. Kotkin

Thanks Michael. Next question is from Paul Patterson from Glenrock.

Paul Patterson – Glenrock Associates LLC

Good morning.

James J. Judge

Hi, Paul.

Paul Patterson – Glenrock Associates LLC

Hey. Just back on the gas infrastructure situation. How do we think about this, the competing issues of having the utility enter into obligations for gas, for electric power versus these other sort of discussions about it happen before capacity options that have more commitment required for capacity providers instead of having the wholesale market sort of drive the need for new gas pipelines? How should we think about this is an?

James J. Judge

I think there is recognition that the market seems to be generating the investment that is needed and the customer’s best interest. And have been instances in the past as you know Paul with as to be intervention in the markets where we have set of significant irregularities, must run contracts is probably the most classic example. So 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 generators stepping up to make the long-term commitment. So to the extent that we have the liability concerns, that we have economic concerns it’s in the interest of our consumers for somebody else to intervene to deal with the irregularities in the market today.

Leon J. Olivier

Yes, and I would just add into that the generators, if you look at the generators, they are all that different economic interest, obviously if you are a nuclear generator, you don’t particularly care where the gas supply is, because the less gas the higher the price is on imported LNG in your margins growth pretty dramatically. And there are other generators that have storage hydro and so forth all of those kinds of assets are optimized when gas prices are very, very high.

So it's unlikely that the market will solve this and if the ISO rules that they proposed go through that would be in the 2018, 2019 timeframe and there are significant penalties around generators that don’t show up on a shortfall day then that could cause a fair number of those that exit the market as we would expect it to do and that means it would be a fairly significant impact on the capacity market in terms of the new supply and demand curve that ISO has also filed for. So there will be a shake out there with the non-nuclear generation capacity over the course of the next seven or eight years.

Paul Patterson – Glenrock Associates LLC

Okay.

James J. Judge

The only thing I would add as well as the sense of urgency is very real, I think and palpable the energy secretary Moniz was here last week and held a conference where this issue or this concern was front and center. In fact [indiscernible] CEO was on one of the panels that were on the agenda that day. So the concern is there and I think we need a timely solution to resolve the problem as quickly as we can.

Paul Patterson – Glenrock Associates LLC

Okay, so when do we see a more formulated, because as you know there are these arguments and stuff that are being raised. When do we see because what is the time line we should be looking for in terms of the NESCO proposal other proposals being – going through the regulatory process – going through the process by which we see the actual policy kind of cautified if you know what I’m saying?

James J. Judge

We think that the sooner the better, we think a time line that would involve an RFP process this summer into this fall in decisions being made, because when you back off or when you take a look at what the saving requirements are, you go through process you select the project, the project is to be decided several regulatory approvals involve there then you beginning construction, I think if you begin the progress now you are still looking for solutions that’s held in the winter of 2017, 2018. So I think we would hope for fast track approach to this effort.

Paul Patterson – Glenrock Associates LLC

Okay and then just finally circling back to in your answer and you guys did mentioned you know obviously this would bode well for your arguments for more than past and I would assume for the coal plate there is well. Is that actually what’s happening on the ground I mean did our people actually seeing this polar vortex stuff, is that changed from people minds or just you guys on the ground what’s your experience in terms of how people actually, we are in the decision making process seeing these projects or seeing these assets or potentially assets versus the – did a change critically on the ground is result of this or…

Leon J. Olivier

Yes, I can this significant change, in the answer is still has some level pulp and paper process knows during the winter time and many of those were shut down because they run off gas for the process because there was no gas, so we consider amount of lay offs during that period. I think you know even the folks that look at the PSNH assets that we currently owned which perform extremely well they understand rolled assets and not going to be around after ever and we need replacement power that is firm, that is clean, that is one lay and that is not subject to lot of the technological issues that other progress versus half.

So there is since that need to have that for the security of the state for the economic development at the stage, Jim mentioned the unemployment rate is very low there is some other major manufactures that would like to move in to – but they have a concern around the availability of energy and the price of energy and so I think with this is done is galvanized the business community elected leaders we have always had labor there, but it is also getting reappoints to rethink there position. So their position in many cases well as no longer, we are not going to support MPT other its what’s the best way to get the project build with the leased in that on the answers. So that’s kind of the dialogue that is taken place throughout much of the answer and with key stakeholders in the answer.

James J. Judge

Great thanks for the color.

Jeffrey R. Kotkin

Thank you, Paul. Next question is from Rajeev Lalwani from Morgan Stanley. Good morning Rajeev.

Rajeev Lalwani – Morgan Stanley & Co. LLC

Good morning, gentlemen. Two quick questions. One on the NESCO process, if the states are choosing between the two alternative. One being more pipeline capacity and the other being RFPs for generation and transmission? And then the second question, I don’t think you touched on this in your prepared remarks and if you did, I apologize, but then the New Hampshire legislation around undergrounding. Some color there would be great as well.

James J. Judge

Sure. On the first question, both our transmission and energy RFP and a gas pipeline RFP are being considered, basically in the same conversations even though this all different solutions and different problems rather. And in New Hampshire, there is sort of periodic legislation. Some of the being considered that would rely – would require more undergrounding and some legislation looking for stricter sighting requirements. Mandatory use of stay transmission power it is so there have been various pieces of legislation, none of which have been enacted to-date.

Rajeev Lalwani – Morgan Stanley & Co. LLC

Great. Thank you.

Jeffrey R. Kotkin

Thanks. Rajeev. And, next question is from Kit Konolige with BCG. Good morning, Kit.

Kit Konolige – BGC Partners LP

Hi, good morning, guys. Two follow-up questions. I may have missed this, but did you talk about are you 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?

James J. Judge

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. So we have increased customer count I think we added that 2,200 customers here in the first quarter. So, the 3.6% weather adjusted is spot on with where we expected today.

Kit Konolige – BGC Partners LP

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 taken comments and adjust your plans and draw new blueprints and go from there? Are there any landmarks or any meetings or any timelines that we can for a different kind of Northern Pass eventually?

Leon J. Olivier

Yes, Kit. This is Lee Olivier. I think I would just summarize it as we are in conversations with many if not all of the folks that you mentioned kind of a 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 answer that we have a coalition in the coalition supports the project quick we know we have the makeup of the coalition as discussed.

Labor we expect to see major labor support, business support and electric leader support and environmental folks of the folks that we're having considerable dialogue with. So will you ever be able to get all of 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 there’s a region around a solution for the project and so later this year we will be able to provide you with better insight and where we are on that work.

Kit Konolige – BGC Partners LP

Great, very helpful. Thank you.

Jeffrey R. Kotkin

Thank you, Kit. We don’t have any more questionnaire. So, we want to thank you joining us today. If you have any further questions, please call John or myself, later in the day. Have a great weekend.

Operator

Thank you. And thank you ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

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