康涅狄格電力 (ES) 2015 Q2 法說會逐字稿

Welcome to the Eversource Energy second-quarter 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.

Thank you, Christina.

Good morning, and thank you for joining us.

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

Some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor Provisions of the US Private Securities Litigation Reform Act of 1995.

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

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

Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2014.

And our quarterly report on Form 10-Q for the three months ended March 31, 2015.

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

Speaking today will be Jim Judge, our Executive Vice President and CFO, and Lee Olivier, our Executive Vice President for Enterprise, Energy, Strategy and Business Development.

Also joining us today are Jim Muntz, President of our Transmission Business, Phil Lembo, our Vice President and Treasurer, Jay Buth, our Vice President and Controller, and John Marrero, our Vice President of Financial Planning and Analysis.

Now, I will turn over the call to Jim.

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

Today, I will cover our strong second-quarter financial results, which were in line with our guidance range for the full year.

Our strong operating performance, an update on several legislative and regulatory items, and I'll close with an update on certain transmission projects.

Let's start with slide 4 and our financial results.

Excluding merger-related costs, we $209.6 million or $0.66 per share in the second quarter of the 2015.

Compared with earnings of $131.9 million or $0.42 per share in the second quarter of 2014.

Over the first six months of 2015, we earned $466.9 million or $1.47 per share, excluding those charges.

Compared with earnings of $373.7 million or $1.18 per share in the first half of 2014.

These results strongly support our full-year earnings projection of $2.75 to $2.90 per share, as well as our targeted long-term annual earnings growth rate of 6% to 8%.

Turning to slide 5, a significant driver in the second-quarter year-over-year earnings growth was the absence of a $0.10 charge we recorded in the second quarter of 2014 resulting from the initial decision from FERC on the allowed transmission ROEs for New England Transmission owners.

There was no similar charge this quarter, plus we continued to realize the benefits of our continued investment in New England Transmission reliability enhancements which added $0.01 to earnings.

As a result, our Transmission earnings totaled $0.25 per share in the second quarter of 2015, compared with $0.14 per share in the second quarter of 2014.

On the Electric Distribution side, higher retail revenues primarily early due to last December's Connecticut Light and Power distribution rate decision.

And the follow-on order from earlier this month involving accumulated deferred income taxes added $0.10 per share to earnings.

I will discuss the July decision more fully in a moment.

We continue to evidence good cost discipline, as we have lower non-tracked O&M expense this quarter.

That reflects a decline in labor and labor-related costs, and added $0.06 to earnings.

I should point out that part of the large O&M decline this quarter, in fact $22 million of the to $56 million you'll see on the income statement, are costs that we don't have any more as we sold our electrical contracting company early in the quarter.

So $70 million of annualized O&M will go away.

There's really no real earnings-per-share impact, as obviously the revenues will go away as well.

Back to the reconciliation for the quarter.

As expected, earnings were negatively effected by $0.06 due to higher property taxes, depreciation and amortization expense associated with storm costs recovery.

Other factors impacting the quarter, which include improved generation earnings and lower income taxes, added another $0.03 per share.

In terms of operations, our electric and natural gas delivery systems have performed well over the first half of the year.

Our electric restoration metric, which represents the average number of months between interruptions, continues to track favorably as our reliability metrics are now consistently in the top quartile of our industry.

Turning to our state legislatures, we had an active and successful spring.

In Connecticut, Governor Malloy signed Public Act 15-107, which, among other initiatives, will allow electric distribution companies to sign long-term supply contracts with interstate national pipelines.

Lee will discuss the significance of act shortly.

Turning to slide 6. In New Hampshire, the Senate and House overwhelmingly endorsed modifications to the state's securitization statutes which are key to public service and New Hampshire's divestiture of its generating assets and recovery of those costs.

The divesture process has now moved to the New Hampshire Public Utility Commission where we filed a comprehensive restructuring and rate stabilization settlement agreement on June 10.

That agreement was signed by a wide range of parties, including the Governor's office of Energy and Planning, two key state senators, senior New Hampshire PUC staff, the office of Consumer Advocate, the IBEW local representing PSNH's unionized workers, and the Conservation Law Foundation, among others.

In addition to divesture of PSNH's 1200 megawatts of generation, other terms of the agreement called for PSNH to defer a distribution rate case until at least mid-2017.

The continuation of PSNH's Reliability Enhancement Program and the related cost tracker, foregoing $25 million of deferred equity return on the scrubber.

And funding by Eversource shareholders of $5 million of clean energy initiatives.

Parties to the settlement agreement have asked the New Hampshire PUC to rule on the agreement by December 31, 2015 which should allow the planned sale process to occur in 2016.

As part of the agreement, the commissions review of Merrimack Station's scrubber investment will end.

We firmly believe that the agreement we filed will benefit all New Hampshire stakeholders over the long term, which is why it is so widely supported.

Turning from New Hampshire to Connecticut, and slide number 7. On July 2, PURA approved a settlement we had reached with the authorities prosecutorial unit concerning the treatment of accumulated deferred income taxes in setting rate base in the last December's general rate case decision.

The settlement restored approximately $165 million of distribution rate base.

And will add about $18 million of distribution revenues annually, and that's retroactive to December 1, 2014.

We recorded $11 million in the second quarter for the period of December 1, 2014 through June 30, 2015.

In Massachusetts, we received two positive orders from state regulators relative to our plans to step up investment in our natural gas delivery system.

The DPU approved a mechanism to recover investments related to the significant upgrade, about 3 billion cubic foot, liquefied natural gas storage facility in Hopkinton, Massachusetts over the next several years.

We expect to invest up to $200 million in that 40-year-old facility, which is critical to helping NSTAR Gas meet its winter supply obligations.

Additionally, the DPU approved the first step in NSTAR Gas' accelerated replacement of its cast iron and untreated steel pipe over the next 20 years to 25 years.

Those expenditures, which are expected to rise to more than $60 million a year by the end of this decade, will also be recovered through a distribution rate-tracking mechanism.

Later this year, we also expect to file a natural gas expansion plan for NSTAR Gas to comply with the state legislation that was approved last year.

NSTAR Gas is our only distribution company where we have a rate case pending.

Hearings in that case where our base distribution rate increase request is approximately $23 million.

Hearings were held in June, and a decision is expected in the fourth quarter.

New rates will take effect January 1, 2016.

I would like to touch on energy rates for a moment.

On July 1, the default energy rates at all four of our electric distribution companies dropped significantly from as high as $0.15 per kilowatt hour to between [$8.25] and $0.10 a kilowatt hour.

This reduction, which is a pass through for us, mostly impacts our essential customers.

The vast majority of whom have not moved to a third-party supplier, and continue to buy their energy from us.

While our customers will benefit this decline through December, rates are very likely to rise again significantly in January.

When New England's acute shortage of natural gas pipeline capacity will again pressure electricity prices.

This seesawing of energy rates is not healthy for our [recent] economy, and Lee will discuss in a moment the long-term initiatives that we have underway to resolve this dilemma.

In Washington, hearings at FERC concluded this month on the second and third complaints filed.

And we got in the return on equity earned by New England Transmission owners.

Earlier this year, FERC reaffirmed a base ROE of 10.57%, down from its previously allowed 11.14%.

We believe that the 10.57% base is a reasonable level.

And booked reserves in the second quarter of last year and first quarter of this year to reflect FERC's final order.

We are due to receive a FERC ALJ initial decision late this year, and expect a commission order in the third quarter 2016.

Turning from regulatory issues to financing.

We're pleased with the outcome of our annual rating agency reviews.

On our first-quarter earnings call, I mentioned that S&P had raised its corporate rating on Eversource and its subsidiaries from A- to A with a stable outlook.

S&P also upgraded Eversource's commercial paper rating to A1.

Subsequent to that upgrade, Fitch raised the outlook for CLMP, PSNH, and WMECo to positive, and Moody's raised its outlook for PSNH and WMECo to positive.

We believe these actions speak loudly about how well we're operating the business, and how many important regulatory items have been successfully resolved.

Now turning to slide 8, I'll provide a brief debate on some significant Transmission projects.

Our share of the Interstate Reliability project, which we are building in northeastern Connecticut, has finished major construction.

And the project was about 97% complete as of June 30.

Right-of-way restoration remains, and we expect the entire project in Connecticut, Rhode Island and Massachusetts to be in service late this year.

We've now made three filings with the Connecticut Siting Council for projects included in the $350 million Greater Hartford Seven Solutions, and all have now been approved with one already under construction.

We continue to estimate that all greater Hartford projects will be completed by the end of 2018.

On the slide, we also highlight some additional Transmission projects in New Hampshire that have been in our forecast and guidance.

On July 21, we and National Grid filed a joint application with the New Hampshire Site Evaluation Committee to build the Merrimack Valley Reliability Project.

Our share of the project would cost approximately $37 million.

Separately, we are going through the prefiling process of the Seacoast Reliability Project, which is part of the New Hampshire ten-year reliability initiative we've been discussing with you for a few years.

We are reviewing our $70 million cost estimate for the Seacoast project, as we incorporate input from the ones that will host the project.

These projects underscore the continued economic growth we see in New Hampshire and Eastern Massachusetts.

Altogether, our capital expenditures totaled $771 million in the first six months of the year.

$324 million of which was spent on our electric transmission system.

We continue to project total CapEx of $1.85 billion this year, $740 million of which will be invested in Transmission.

That concludes my formal remarks.

Now I will turn the call over to Lee

Thanks, Jim.

I will provide you with a brief update on our major capital initiatives, and then turn the call back to Jeff for Q&A's.

Let's start with Northern Pass, profiled on slide 10.

The US Department of Energy released its Draft Environmental Impact Statement on July 21.

We have begun our review of the document, and do not believe it poses any unanticipated challenges to the construction of the project.

We were pleased that the Draft EIS concluded that there would be a very low to low visual impact on our northern sections of our preferred route.

As expected, the DOE reviewed a number of alternative routes for the project in addition to our preferred configuration.

We will carefully evaluate these alternatives.

The considerable breadth of these alternatives should ensure that the project configuration ultimately approved by New Hampshire regulators will have been analyzed by DOE.

While the Draft EIS is now released, is the DOE has scheduled public hearing on the report for early October, and asked for written comments by the end of October.

Now that the DOE has issued its Draft review, we expect to file with the New Hampshire Site Evaluation Committee for our state siting approval in the early to mid-fall.

The new state process requires a series of public meetings on the project at least 30 days before the application.

So you should expect those meetings to be scheduled soon.

Once we file our application, the site evaluation committee will have up to two months to determine that the submittal is complete.

And then up to 12 months to rule on it.

Our state application will incorporate feedback from the DOE's Draft EIS, as well as from the ongoing outreach in New Hampshire to ensure it is viewed favorably by a wide range of stakeholders.

As part of our engagement with New Hampshire stakeholders, we announced on June 16 a new and unique partnership that will create significant opportunities for New Hampshire workers.

And businesses to participate in our upcoming transmission projects in the state.

This would include Northern Pass and about $800 million we expect to invest in other New Hampshire projects over the next five years, some of which Jim has referenced earlier.

The jobs program focuses on three key areas of employment.

They include a commitment to hiring New Hampshire workers first, a commitment to New Hampshire-based construction-related companies, many of them family-run, to have an opportunity to bid on our projects.

A first of a kind training program to allow New Hampshire apprentices to be paid while training for high demand work on electric transmission construction.

This effort is being coordinated with the IBEW, and our major electrical contractors.

We look forward to the many of these New Hampshire residents and companies working on Northern Pass.

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

We continue to estimate the cost of approximately $1.4 billion for Northern Pass, but that could change depending on the conditions related to the regulatory approvals.

Turning to slide 11.

You can see that we expect to receive both state and federal siting approvals of the project in late 2016.

Commence construction around the end of 2016, and have the project substantially complete on both sides of the border by the end of 2018, with testing and entry into full commercial operation in the first half of 2019.

This schedule is similar to what I discussed with you in May.

Turning to slide 12.

New England continues to make progress toward addressing significant energy challenges facing the region.

One of these challenges is the need for new clean sources of power, especially as we witness the ongoing retirement of older coal, oil and nuclear units.

Northern Pass will provide some of that clean power, but other additional sources will be needed to meet the renewal energy and carbon mandates New England and other states have enacted into law.

In late February, the state of Massachusetts, Connecticut and Rhode Island jointly unveiled a draft solicitation for clean energy sources that will require new electric transmission to be built.

The draft RFP asked for proposals for power purchase agreements, as well as for the construction of transmission that would tap into clean energy.

In late in June, the final proposed RFPs were submitted to Massachusetts and Rhode Island to regulators for approvals.

Connecticut legislation does not require that step.

We expect that regulatory sign-off on their RFP will occur over the next couple of months, and the RFPs will be released to potential bidders shortly thereafter, with bids due late this year.

In Massachusetts, Governor Baker filed legislation on July 9 that calls on the state to purchase up to 18.9 million megawatt hours annually of clean hydroelectric power and other renewable energy.

That equates to about 2400 megawatts of capacity.

We expect the legislature to take up the Governor's bill this fall.

Earlier this week, Governor Baker's energy secretary, Matthew Beaton, said that the governor has made the bill one of his priorities.

Since without hydropower, the state will fall short of emissions reductions targeted by the state's landmark 2008 Global Warming Solutions Act.

In addition to taking steps to address its clean energy goals, New England has also made significant progress to its improving the availability natural gas to fuel power generation during the winter.

As I discussed on our first quarter conference call, New England and federal policy makers are very concerned about the shortage of natural gas capacity into the region during cold weather months.

New England is challenged by a lack in the gas pipeline capacity into our region, a shortage of natural gas storage, and a heavy and growing dependence on natural gas generation.

These constraints caused New England to suffer the three highest price months ever in New England for wholesale electricity prices in January and February of 2014, and in February of this year.

Further, natural gas prices in New England this past winter were almost double the national average, even though we are located so close to the Marcellus gas fields.

Without action, the fuel constraints that we are seeing are driving skyrocketing prices will only continue and intensify.

[Ice] in New England recently stated that it expects 10% of the region's generation fleet to retire by 2018, and possibly another 5000 megawatts or 2020.

These units will be oil and coal-fired.

More natural gas generation will take their place, pressuring gas supplies and customer rates even further.

The region's policy makers recognize the severity of this challenge and are taking action.

Turning to slide 13.

Let's start with the Connecticut legislation Jim mentioned earlier.

On June 22, Governor Malloy signed public act 15-107.

This bill provides clear authority for state regulators to allow electric distribution companies to sign long-term supply agreements with interstate natural gas pipelines.

We expect the Department of Energy and Environmental Protection to solicit proposals later this year.

In Massachusetts, the Department of Public Utilities opened a docket in April to examine whether it should consider allowing electric distribution companies to contract for interstate pipeline capacity.

We, along with National Grid and the Governor's Department of Energy resources, strongly believe the DPU's authority to approve such contracts is clear under state law.

Initial comments were filed in June, and reply comments in early July.

Although the DPU has not set a timeline for the remainder of the investigation, we anticipate the DPU will issue its findings later this summer or early fall.

In New Hampshire, the Public Utilities Commission opened its own docket in April to investigate the means by which electric distribution companies could ameliorate adverse wholesale electric market conditions caused by natural gas constraints.

Stakeholders filed comments in June.

Further, the PUC staff released its preliminary conclusions earlier this month, that electric distribution companies have the necessary authority to contract financial gas capacity.

The PUC staff will provide a report to the commission by September 15 of this year.

In Maine, the Public Utilities Commission conducted an RFP late last year as part of its mandate to bring up to 200 million cubic feet a day of incremental natural gas capacity into the state.

Access Northeast bid into that RFP, and in May, Central Maine Power filed with the main PUC recommending that it be allowed to contract with Access Northeast to bring in additional gas capacity.

The consultant hired by the PUC analyzed the proposals, issued its report earlier this month concluding that Maine going it alone would not be justified.

We believe this reinforces the need for a multi state effort.

All of these actions point to the increased recognition by policymakers that New England requires additional interstate pipeline capacity to ensure electric grid reliability and stable pricing.

As we have said previously, we believe that the $3 billion Access Northeast project we are developing with Spectra Energy and National Grid is ideally suited to address New England's natural gas infrastructure challenges since it would include upgrading Spectra's existing pipelines in New England.

Our project is unique, uniquely situated to deliver increased quantities of natural gas to the region's newest and cleanest generators.

Since Spectra's pipelines and our alliance with Iroquois Pipeline connect us to directly to more than 70% of the region's gas-fired units.

To remind you, Spectra and Eversource would each own 40% of the project, and National Grid would own 20% of the project.

The project's open season ended May 1. And it received a strong response from both electric and natural gas distribution companies.

Access Northeast has commenced the process of negotiating long-term contracts with those distribution companies.

We expect that pipeline customers will file those contracts with the state regulators later this year with the goal of securing state regulatory approvals in 2016.

With respect to siting and permitting, we plan to commence FERC our prefiling later this year.

This will facilitate a formal certificate filing at FERC in 2016.

We expect to bring the pipeline into service for the winter of 2018 and 2019, assuming expeditious approvals by federal and state authorities.

Because of the longer construction timeline for LNG facilities, we anticipate the storage element of the project will commence service after the pipeline.

On July 27, we announced the LNG element of Access Northeast at a public meeting in Acushnet, Massachusetts.

That element involves the construction of 6.8 bcf of LNG storage in Acushnet, where Eversource currently operates an LNG facility.

This LNG facility has been operated safely and reliably for nearly than 45 years.

The combination of the enhanced Spectra pipeline system and the additional domestic natural gas, will allow us to ensure up to 5000 megawatts of natural gas generation will remain online even during the coldest winter months.

Now I'd like to turn the call back over to Jeff for Q&A.

Thank you, Lee, and I will turn the call back to Christina, just to remind you how to enter questions.

Christina?

(Operator Instructions)

I will now turn the call back to Jeff.

Thanks, Christina.

Dan Eggers, Credit Suisse.

You're on the process right now for Access Northeast.

You will prefile this year, FERC will give you a response.

What time in 2016, and then when would you expect a official formal approval and then start actually spending money on construction under the timeline you laid out today?

In regards to the prefiling, we will do the prefiling approximately in the fourth quarter of this year.

And then we will do the certificate filing somewhere between the third quarter and fourth quarter of next year.

And clearly at the beginning of this project, the capital expenditures or investments are very low.

And what we are doing now is we're putting together the capital flows and cash flows for next year, and we'll have a better sense of those later in the year, most likely at our conference in the fall in November, our EEI conference.

So we'll look for the capital update.

But probably no real dollars going to work until what 2017, 2018?

Is that realistic?

I think that is a reasonable conclusion.

And from a confidence, obviously the open season is showing interest.

Do you need to see more state approvals in some of these processes you have pending before everybody's going to be on board for signing firm agreements at this point?

Well in the case of Connecticut, they don't need commission approval.

What's happening there is the Department of Energy and Environmental Protection are putting together a RFP process.

They're in the midst of doing that.

They will go out with an RFP.

Massachusetts we expect by late this summer, early fall, will have signed off on the RFP, and it will be issued then.

And essentially, once the RFP is issued, and this is on electrics, once the RFP is issued, there is about 75 days that would be required to get your bid in.

So we could expect bids in the fall, and to choose the winners late this year, early next year.

And on gas, it really is going to be -- it's a little bit different.

The only state that wants to use an RFP process is Connecticut.

The other states right now have not really made the determination whether they want to follow that, or just use the standard LDC process, where we will file -- the EDCs will file the precedent agreements with the regulatory bodies.

And that will kickoff an approval process that could take anywhere from three months to six months.

So we shouldn't see the bulk of these contracts somewhere around year end, I guess, then the gas utilities could be a little bit later.

But within the next six to nine months we'll know how firm and who's presumably going to take the capacity?

Yes, I think that's a good estimate of time.

Six to nine months is a good estimate.

Okay, very good.

Thank you.

Thanks, Dan.

Julien Dumoulin-Smith, UBS.

So the first quick follow up on the last question there if you can.

In regards to the procurement, as you're thinking about what's contemplated, and obviously it is early days for Connecticut and Massachusetts.

Will this ultimately be sufficient to get your projects off the ground?

What's the quantity contemplated as, Lee, as you are seeing the frameworks proposed, I suppose, between just those two states today to get your project and perhaps other projects off the ground?

What's the total volume, if you will?

Julien, this is Lee.

You are referring to the gas side?

Yes indeed.

So the gas side, we expect to get something very, very close to the 900,000 dekatherms per day.

Okay.

Great.

And then a second question somewhat related.

Going towards the other side of the house on the Transmission.

As you look at the Massachusetts legislation, how do you think about that tying into the present RFP that you just discussed?

Would that ultimately be an upsizing, or how would that ultimately get feathered together?

And this is in regards to the three state electric RFP in Governor Baker's proposed legislation?

Exactly.

How do you see those two working together?

Currently, without that legislation, then Massachusetts really would be interested in this deliverability commitment model.

Whereby you buy, essentially -- you pay for transmission.

And you get a supplier on the other end that will deliver electricity upon an agreed upon, essentially, capacity factor or numbers of megawatt hours over the course of the year.

So that would be their option there.

If Governor Baker's legislation passes, then you really have the full range inside of the three state RFP.

You would have the deliverability model, you could to transmission with PPAs, or they could do PPAs as well.

So just in the full range of what the options are in the current RFP.

Great.

Thank you.

Thank you, Julien.

Stephen Byrd, Morgan Stanley.

I wanted to follow up on Dan's question just on the approval process.

And, Lee, you laid out a six- to nine-month timeframe.

And on the gas side, could you give us some indication in terms of just key regulatory items we should be trying to follow throughout the course of the fall and through the wintertime?

Just so we can better understand the sequence or the key things we should be looking for there?

Clearly, a key thing is the RFP process in Connecticut that will be run by ED, which we expect to take place this fall.

It will be the signing of the precedent agreements by the EDCs and LDCs, because it's both.

And the filing of those precedent agreements that will take place essentially late third quarter, early fourth quarter, it will be the approval by the Massachusetts DPU of the RFP process.

So those are the things that you can expect to see in the -- not the approval of the RFP process, but the approval of the docket that allows the EDCs to purchase gas infrastructure.

So those are some -- again, I set the prefiling we'll do late this year.

And you'll hear -- we will continue to do the further rollout of our Acushnet facility, our LNG facility in Acushnet, and you'll hear more about that.

Okay.

That's very helpful.

And just shifting gears over just follow-up on what you had mentioned in Massachusetts with the Governor's legislation proposal.

It's great that it sounds like it's a key priority for the governor.

Could you just speak to politics for the proposal broadly?

Your sense for are there key elements or features that have drawn opposition?

Or is this something that is generally, you think, broadly you've supported politically?

How do you think about the politics of it?

Well, Jim, you may want to catch that one up a little bit.

Stephen, this is Jim.

I'd characterize it as similar to what we saw in Connecticut.

Governor Malloy's Connecticut energy strategy recognized that there are low-cost clean sources available in terms of Canadian Hydro that can help the state achieve its carbon reduction goals.

I think the same mentality exists in Massachusetts among the policy makers.

So obviously it's draft legislation at this stage, it would need to be approved on Beacon Hill, and then signed by the governor.

But we think there is a recognition that clean resources are available and within reach, and we need to be on with it in terms of enabling the commitments to be made.

Great.

Thank you very much.

Thanks, Stephen.

Travis Miller, Morningstar.

On the O&M cost side, if you take out that business that you divested there, how are you thinking in terms of tracking your O&M savings targets for the year?

Behind, ahead, on track so far this year?

Yes.

The guidance that we gave, Travis, for the year was O&M reductions of 2% to 3%.

And when we adjust out the sale of that electric contracting business, I would say we are probably closer to 4% year to date.

So we are out a little ahead of it.

I would caveat that by saying that we do know that there is some timing in those numbers that we have gas and electrical maintenance plans that are lagging behind slightly.

So we'll probably catch up on some of that.

So while we're ahead of plan year to date, I think the guidance continues to be 2% to 3% for the year that we are comfortable in giving.

And that is that nets out obviously the -- we've excluded the business that we have sold here in the second quarter.

Okay.

And then what was the full earnings impact, the bottom line impact, from that business if you include that revenue loss?

It was relatively small fractions of a penny.

$2 million a year.

That order of magnitude.

Okay.

Great.

Thanks so much.

Thanks Travis.

Shah Pourreza, Guggenheim.

Just one question on Northern Pass.

The jobs program that was announced, as well as the property tax payments reductions.

Could we just get a little bit of a sense on what form the basis of those terms?

Was this from feedback you received from constituents within the state, and is this the foundation for settlements?

Yes, Shah, this is Lee Olivier.

We're not looking at this as a foundation for settlement, because we really believe that the process that it's in place now and the answer is best left through a litigated process.

And we think ultimately out the other end, it will have more integrity if it is through a litigated process.

Clearly, New Hampshire wants to understand, being the host, they want to understand the values of that line to New Hampshire, from the standpoint of what does it do to lower electric costs to the extent that they can have a power purchase agreement.

To the extent that it creates jobs, both the during the construction and permanent jobs, to the extent that there is other financial value to the state.

And so -- and this is after a lot of conversations with elected leaders, municipal officials, and other key stakeholders in the region, including obviously labor, the environment.

And so what we will have when we announce the project will be a comprehensive value proposition that we will present to New Hampshire that will provide significant benefit in terms of jobs, revenues, tax revenues, and other support for the state over a long period of time.

So we believe, coupled with the Draft EIS, coupled with our own outreach around the existing route and changes that we could make reasonably, that the combination of all of those will have wide acceptance in the state when we file our application at the SEC in the early fall timeframe.

Okay, got it.

So just one clarification.

So, the jobs program and the property tax payments, that was from conversations you have had with constituents within New Hampshire?

Well the property tax payments will be just be the standard mill rate on any given area.

In other words, how much infrastructure is in a town, what's the particular town's mill rate, what's that infrastructure worth, what do we have on the books and they will be paid accordingly.

Very standard is how we do all of other transmission.

And then the other services provided will have been, if you will, discussed with the key stakeholders and we will reach a joint position on those.

Okay.

Perfect.

And then just on Access Northeast.

Once you get the firm contracts sometime next year, is there a point where we can get closure as far as upsizing the pipe through laterals and compressors?

And then just lastly on the storage project, is there any quantification on what that spending outlook would be?

Yes.

On the latter one, the storage, that is approximately $800 million of investment out of the $3 billion of the project investments.

So that's about $800 million.

And those are -- they're our first cut of the numbers that's doing some engineering, having an engineering consultant, and understanding where the market is right now for LNG.

So we think, right now, $800 million is a good number for a 6.8 LCF.

And if you look at up the project, the LNG would provide about 400,000 dekatherms a day, the pipelines would provide around 500,000 dekatherms.

So our project right now, it's approximately 1 bcf, and that's the project that we will proceed with at this time.

Great.

Thank you so much.

You're welcome.

Thanks, Shah.

Michael Lapides, Goldman Sachs.

Congratulations on a good quarter.

Two separate questions.

The first one, you have two big projects, two really big projects, Northern Pass and Access Northeast.

There are other market participants who are proposing new transmission down into New England, some of which with more underground routing than overhead.

There's also one or two other parties or consortium trying to get new major pipeline build.

Can you talk for each of those two projects?

The competitive positioning, the difference between your project recommendations and some of the others that are out there on the market.

Sure.

Michael.

This is Lee.

I think looking at Northern Pass, clearly, the entity or utility that has the most hydro power available in North America is Hydro Quebec.

And they are the closest geographically to new England, and have tie lines into New England currently.

And they are our Partners, and they are only working on one interconnection between Quebec and New England, and that is ours.

So they are not working on any other interconnection into New England.

So they are our Partner here in New England.

So what that would lead you is to if you look up other hydro sources they would be in the Labrador, Newfoundland region.

And those are small in nature.

They are under development, could show up in the next 15 years from now.

But they don't provide any meaningful supply into New England during that period of time.

So from that standpoint, our project at 1200 megawatts and you look up big part of what is driving Governor Baker and others.

It's all about carbon reduction.

If you want to hit your 50% or 80% carbon reduction by 2050, you need a lot of energy that doesn't produce carbon that runs around the clock, and clearly, that transmission project is the best one to go do that.

There will be other projects that will be wind projects.

Some of them may have run of the river firmed up by their wind with run of the river firming the wind up.

But those are smaller projects in nature, they're 400 to 500 megawatts.

And then you're probably looking at some big winds projects, we'll say farther up in places like Maine.

You have all the issues of building large transmission infrastructure to collect, relatively speaking, small amounts of energy.

When you look at the wind capacity factor of 35%, the intermittency of that probably doesn't have a huge carbon impact when you consider what you are paying for it.

So that's what the competition looks like there.

On the gas side, it's real clear.

We are building a project that interconnects with 70% of the region's generators.

It is using existing right aways, existing LNG facilities.

It will pick up both EDCs, LDCs, it has future potential expansion capability.

The competition is building a pipeline that is designed around serving LDCs, and is in an area where it is very difficult to interact with a whole lot of that 70% of the generation I just talked about.

So we think from that standpoint, we think that project is very well-positioned, and we had a very successful rollout of our LNG in Acushnet, Massachusetts earlier this week.

Got it.

One follow-up, easier question.

When you are thinking about whether there is a new normal for gas utility demand growth, especially as the residential and small commercial.

How do you think about that, and how different is that across your systems?

This is the Jim.

The long-term gas growth rate that we are assuming in our five-year plan in the guidance that we've provided is 4%.

Now, you may not get those growth numbers in other regions of the country where the gas penetration is more significant.

We have a huge opportunity in Connecticut, as well as Massachusetts, in terms of converting customers to gas heat at their homes.

In fact, we've got attractive mechanisms in Connecticut in terms of cost recovery for all that.

So we're targeting about 11,000 conversions this year.

In spite of the decline in oil prices, we're actually -- we'll have a plan.

I think we've signed up about 4800 in the first half of the year.

So we've got 2% plus growth just on new customers, and then, obviously, the volume is likely to grow as well.

So we feel pretty confident about our 4% growth rate long term.

Again, I don't know that I would apply that to other utilities or other regions of the country.

Got it.

Thanks guys.

Much appreciated.

Thanks Michael.

Andrew Weisel, Macquarie.

Two questions on Northern Pass.

Andrew, could you just speak up a little bit?

Sure.

Sorry.

Two questions on Northern Pass.

First, were the RFPs that you described.

Given that this is an economic base project, do those really matter if the project succeeds in bidding for those RFPs?

And if so, would that effect your economics, Hydro-Quebec's or the rate payers?

I think -- this is Lee, Andrew.

I think the way we would answer that is, there is this existing RFP process that has been made available to all entrants.

So obviously, we in HQ would enter this project into that process.

Because to go forward independent of that would provide the others that would bid in and were chosen to have the competitive advantage over Northern Pass.

So I think is appropriate that this project is -- it takes part in that RFP process.

And in that case, as you know, in the three states, there would be some load share spreading of that cost over those three states.

And each state, obviously, will be different, based upon the specific part of their either RPS portfolio and/or carbon reduction mandates that they have.

So that would have to be determined by the three states as part of that RFP process.

Okay.

Thank you.

The next question from the DOE's Draft EIS.

The cost estimates of undergrounding look quite a bit lower than what you guys have talked about.

This expensive option they have is 4B at $2.1 billion to underground debt.

Is there some disagreement in how they make that estimate?

Do you still think that it would be prohibitively expensive to underground it?

Or in light of the DOE's estimate, is that something that you might consider?

Yes.

The numbers that DOE used in their estimates were the direct costs.

They didn't use the fully loaded costs with AFUDC, and financing, and so forth.

So they just use the direct costs, that's why their costs were different than our costs.

So do you still consider -- sorry, continue.

The costs that we use are costs that our current industry market costs, either for undergrounding that we do or have done and/or updates from our contractors.

So we think our costs are pretty accurate.

And I think the main difference with the DOE is they just use direct costs.

So you still see fully undergrounding as prohibitively expensive?

Yes.

We see undergrounding, full undergrounding, as unnecessary, prohibitively expensive, and a project -- some project modifications could be done with some additional undergrounding.

That ameliorates, essentially, the issues raised inside of the DOE EIS.

If you look at the DOE EIS and analyze the essentially three areas, the northern area, the central area, and the southern area.

It breaks out the White Mountain's National Forest.

In all of the areas, if you look up the scenic impacts are all rated on a scale from 0 to 5.

They are all rated either very low, or low in terms of the scenic impact.

Nevertheless, as a result of that outreach we've done, there is some additional undergrounding that can be done that will make those numbers even lower.

Without having to underground the entire project.

Thank you very much.

Yes.

Thank you, Andrew.

Caroline Bone, Deutsche Bank.

Just a minor question really, because most of my questions have been asked.

But is there anything that could cause you to book a reserve related to the pending second and third ROE complaints?

Would the ALJ decision be a potential catalyst?

There is a potential that the ALJ decision comes down by year end.

I think it targeting, in fact, a late December number.

And obviously, we will assess the merits of that recommendation, and whether or not it warrants a reserve or not.

So the timing is such that we do expect that ALJ decision the end of this year.

However, the final FERC ruling on it would be the third quarter of 2016.

So we'll have to look at the facts and circumstances of that order before we could tell you whether there's going to be a reserve or not.

All right.

Thank you.

Thank you, Caroline.

We have no more questions in the queue.

So we just want to thank everybody for joining us.

We know you have additional calls later this morning.

But if you have follow-up questions, please give us a call.

Thank you very much.

Thank you.