康涅狄格電力 (ES) 2017 Q2 法說會逐字稿

Welcome to the Eversource Energy Second Quarter Earnings Call.

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

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

I will now turn the call over to Jeffrey Kotkin, Mr. Kotkin, you may begin.

Thank you, Sylvia.

Good morning, and thank you for joining us.

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

As you can see on Slide 1 of the slides that we posted last night, 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 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, 2016, and the 10-Q for the 3 months ended March 31, 2017.

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

Turning to Slide 2. Speaking today will be Phil Lembo, 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 Jay Buth, our Vice President and Controller; John Moreira, our Vice President of Financial Planning and Analysis; and Christine Vaughan, our Treasurer and Vice President for Regulatory.

Now I will turn to Slide 3 and turn over the call to Phil.

Thank you, Jeff.

So today, I'll cover second quarter and first half financial results, the status of key regulatory dockets, the status of our Aquarion Water Company transaction and an update on our capital plan and several transmission projects.

So let's start with the financial results for the quarter in Slide 3. Earnings were up $0.08 per share in the second quarter of 2017 compared with the second quarter of 2016.

We earned $0.72 per share in the second quarter compared with $0.64 per share in the second quarter of 2016.

On the electric distribution and generation side, we earned $0.38 per share in the second quarter of '17 and that compares to $0.32 in the second quarter last year.

This increase was primarily due to lower operations and maintenance costs.

We also benefited from higher demand revenues due to warmer weather than the prior year.

Our transmission segment earned $0.30 per share in the second quarter of '17, and this compares to $0.29 per share in the second quarter of last year.

The primary driver of this earnings growth was higher transmission rate base as we continue to invest in transmission projects that enhance the reliability of the New England power grid.

I'll provide an update on key transmission projects that are driving this in a moment.

The benefits from the greater transmission investment were partially offset by our annual reconciliation of costs and revenues from the prior year in accordance with FERC tariffs.

This reconciliation takes place annually in the second quarter.

On the natural gas distribution side, we earned $0.01 per share in the second quarter of 2017.

This compares to earnings of $0.03 per share in the second quarter of the previous year.

Lower earnings were due to several factors: milder early spring weather, higher depreciation and higher O&M costs.

At the Eversource parent and other, we earned $0.03 per share, and this compared to a relatively flat results in the second quarter of 2016.

The primary driver was related to earnings from a long-held investment in a fund that invests in renewable energy projects.

In total through 2016, the earnings from this investment were pretty much breakeven.

However, the market for renewable projects has matured and performed well over the past year, resulting in higher equity earnings in the second quarter from this investment of about $0.02 per share and this compared to a small loss of about $0.01 per share in the second quarter last year.

So going forward, we don't expect ongoing earnings from this investment will have a material impact on the earnings.

Turning from the second quarter to the first half results.

We earned $1.54 per share in the first 6 months of '17 compared to $1.41 per share in the first half of last year.

Improved results were due to higher transmission earnings, higher distribution revenues, lower O&M and improved results at the parent.

For the full year, we continue to expect to earn between $3.05 and $3.20 per share, and for the long term, we continue to project 5% to 7% EPS growth.

From operations, I'll turn to our regulatory activity and start in Massachusetts with the Massachusetts rate case, and this is on Slide 4. Hearings have concluded on the rate case, except for rate design topics.

We expect a decision on the financial aspects of the case by the end of November with the rate design decision around year-end.

New rates would be effective in January of 2018.

And to date, we've had no surprises in the rate review process.

In New Hampshire, binding bids on our Public Service Company of New Hampshire generation fleet are due next month.

And there, too, the overall divestiture process is moving along well and we expect regulatory approval of the sale by the end of the year, with securitization activities to follow soon after the closing.

From our state regulation, I'll turn to Slide 5 and the various New England transmission ROE dockets before FERC.

As you may recall, on April 14th of this year, the DC Circuit Court of Appeals vacated FERC's 2014 order that lowered the base ROE for the New England Transmission Owners from 11.14% to 10.57%.

Now before FERC commissioners, is not only the vacated order from that Complaint 1, but the ALJ recommendations from Complaints 2 and 3 which have not yet been decided.

So it's unclear whether FERC will issue orders on all three complaints at the same time or what the timing is of when this will occur.

We've been conferring with other New England transmission owners about the appropriate billing for transmission service in New England in light of this April circuit court decision and for pending complaints.

And in June, the region's transmission owners, including Eversource, filed with the FERC to revert back to the last approved ROE that was approved at 11.14%.

In the filing, the transmission owners proposed that the rate be effective on June 8, and billing the new rate to customers would not start until 60 days, after FERC has a quorum.

And as we all know, that has not occurred at this time.

The financial results we reported last night still reflect the 10.57% ROE and the 11.74% cap on incentives that was vacated by the court.

Our transmission revenues are based on what we bill our customers.

Therefore, there will be no change in our transmission revenues until our rates are changed prospectively.

As a reminder, every 10 basis points of change in transmission ROEs results in about a $3 million after-tax earnings annually.

Next I'll turn to Slide 6 and the exciting announcement we made last month.

On June 2, we announced an agreement to acquire Aquarion Water Company from Maquarie Infrastructure Partners and others for approximately $880 million in cash and assumption of $795 million of Aquarion debt.

Aquarion is a very well-managed water company with operations in the three states we already serve: Connecticut, Massachusetts and New Hampshire, with 90% of the operations being Connecticut.

Several weeks ago, we filed regulatory applications in each of the states, seeking permission to consummate the transaction.

And we expect to close the deal by the end of this year.

Connecticut, as I said, where 90% of the business is located, has already established a schedule, with the final decision due before the end of October of this year.

This transaction fits very nicely with our strategy to invest in critical infrastructure and to develop clean energy solutions for customers.

Macquarie had owned Aquarion for a decade, and its decision to sell the business coincides with our divestiture of PSNH's generation fleet.

So, in addition to being an excellent strategic fit, the timing of the opportunity was also good.

We are exiting a generation business that was shrinking because of state statutes that precluded us from any expansion, and we're entering a water distribution business that we expect will see decades of growth ahead due to the need for replacement of aging infrastructure.

We expect Aquarion to help support and extend our projected 5% to 7% EPS growth.

We'll not be issuing any equity in association with this transaction.

The cash portion of the transaction will come largely from the net proceeds from the sale and securitization of our New Hampshire generating assets.

And as a reminder, nearly $800 million of gross proceeds are expected as part of that transaction.

We anticipate that Aquarion will operate pretty much as it does now post closing.

As you know, we are not currently in the water business.

We also expect Aquarion's earnings to substantially offset the loss of PSNH generation earnings.

And we expect Aquarion's earnings to grow over time as we invest needed capital in the business.

Connecticut has a constructive regulatory structure for water companies that includes revenue decoupling, an infrastructure investment tracking mechanism and the ability to include in rate base acquisition costs related to the purchase of small, financially distressed water companies.

There's much fragmentation in the water business today, and over the last several years, Aquarion has acquired over a dozen smaller water systems, and I expect this trend would continue.

We're very excited about the additional business diversity and long-term growth opportunities the water business will provide.

We are also very pleased that Aquarion will be located locally and owned locally.

Before I turn the call over to Lee for the status report on some of our major projects, I want to provide you with our customary midyear update on capital expenditure plans.

So our capital expenditures total about $1 billion in the first half of 2017, up about $100 million from the first half of 2016.

Transmission investments totaled approximately $375 million in the first half of 2017, and we continue to target nearly $1 billion in transmission investments for the year.

As you can see on Slide 7, we continue to make progress on a number of the major transmission reliability projects.

I wanted to spend some time discussing Northern Pass spending.

Northern Pass accounts for $21 million of our transmission capital invested this year, and we expect that number to rise considerably beginning next year.

Lee will provide you with an update of the project in a moment, but as you can see in the slides and from the press release relating to our Massachusetts RFP we issued yesterday, we're now anticipating a second half of 2020 as the in-service date for the project.

We expect that the vast majority of the work on Northern Pass will be completed in '18 and '19, but we do expect a few hundred million dollars of the project will move into 2020.

We are currently developing detailed operating plans for 2018 and beyond, and we fully expect to provide an overall capital spending plan for 2018 that is consistent with the plan we released earlier this year.

We expect to offset the lower level of expenditures in Northern Pass in 2018, with increased investments in electric resiliency programs, natural gas infrastructure and natural gas expansion projects.

We also expect, depending on the exact closing of the timing of the Aquarion transaction, nearly $100 million of capital expenditures at the water business.

We will provide you with specific capital expenditure levels for '18 through '21 for all segments when we update our long-term forecast in February.

We expect these investments to fully support our projected 5% to 7% long-term EPS growth rate.

With that, I'll turn the call over to Lee.

Okay, thanks, Phil.

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

Let's start with Northern Pass in slide 8. The New Hampshire Site Evaluation Committee has completed more than 20 days of final evidentiary hearings for the project.

Remaining hearings are scheduled to run through September.

And we've been quite pleased with how they have proceeded so far.

We consider the New Hampshire SEC's schedule to be supportive of the project receiving all of its approvals necessary to commence construction in early 2018.

Hearings in June and July focus on construction of the line, its impact on the region's power prices, and the considerable effort we are devoting to minimize environmental impact of the project.

We believe our witnesses have made a very persuasive case as to why the project should be approved as proposed.

It will bring billions of dollars of benefits to the state of New Hampshire, including an estimated $60 million a year in electric market savings, $30 million to $35 million a year in property tax revenues, $200 million over a 20-year period as part of the fuller New Hampshire economic development and clean energy fund and up to 2,600 jobs during the construction period.

We have pledged to give priority to New Hampshire residents and businesses for construction work.

In addition, the SEC permit we need to secure a presidential permit from the U.S. Department of Energy.

According to its website, the DOE expects to issue a final environmental impact statement in August.

That will position the DOE to issue a presidential permit by the end of this year.

We continue to expect Hydro-Quebec to receive its final national and provincial permits for the Canadian portion of the project later this year.

The New Hampshire PUC already has reviewed a number of items related to Northern Pass.

Last year, it authorized Northern Pass Transmission to operate as a utility in the state of New Hampshire.

In June, the Hampshire PUC approved NPT's licenses to cross public waters and lands.

Additionally, both the New Hampshire Department of Transportation and the State Department of Environmental Services have approved the necessary permits to construct Northern Pass, subject to final approval by the New Hampshire SEC.

Receiving the New Hampshire SEC and presidential permits by year-end would support commencing construction in early 2018.

You may recall that during our first quarter earnings call, we noted that we expected to firm up our construction schedule around this time after concluding a comprehensive review of the project with our equipment vendors and contractors.

We have now completed that review, with a particular focus on the timing and cost of the converter station and the 60 miles of underground cable.

We also wanted to get through certain key elements of our New Hampshire SEC testimony, particularly the seven days of hearings on construction, which ended in June.

Based on our firm contracts, we expect that if we receive final permits for the project by the end of this year, we can complete the project in the third quarter of 2020.

At that time, Northern Pass would be fully constructed and operational testing would commence, allowing the project to enter service prior to the critical 2020 to 2021 winter period.

We believe the schedule would put us significantly ahead of any other major project to import Canadian hydro into New England.

Our confidence in the construction schedule was also supported by the firm contracts we have with two of the most preeminent firms in the world in terms of electric transmission design and construction: ABB and Quanta Services.

Turning to slide 9, yesterday, Eversource Energy Transmission Ventures and Hydro-Quebec jointly bid Northern Pass into the Massachusetts Clean Energy RFP.

We believe that this bid will be extremely competitive in the Massachusetts solicitation due to the advanced stage of our project development.

To remind you, by 2022, Massachusetts is required to contract for 9.45 terawatt-hours a year of clean energy.

Page 1 of the RFP states that of the total 9.45 terawatt hours of cost-effective clean energy contracts being sought in this RFP, the distribution companies encourage proposals which include clean energy generation able to commit to begin deliveries prior to the end of 2020 to maximize the Commonwealth's ability to meet its Global Warming Solutions Act goals.

We believe that these provisions support our joint bid since we are so much further along the product development process than other bidders.

Additionally, Northern Pass would reduce Massachusetts' electric sector carbon emissions by 25%, and as a result, get Massachusetts halfway to its mandated reduction for the sector by 2050.

The current Massachusetts RFP schedule indicates that projects will be selected for negotiations by January 25 with regulatory filings next spring.

Separately, an RFP exclusively for offshore wind was issued to the market at the end of June with bids due December 20 and expected contract filings with the DPU by the end July 2018.

The RFP calls for interested bidders to submit a conforming proposals for 400 megawatts, but also stated, alternative bids are up to 800 megawatts would be considered if bidders can show that a larger project would provide significant net economic benefits to customers.

Bidders can also submit an alternative bid for as little as 200 megawatts.

Bay State Wind, a 50-50 partnership between Eversource and DONG Energy, will bid into this RFP.

Bay State Wind's 300-square mile tract off the Massachusetts coast is a very attractive location and is expected to be able to host wind turbines capable of producing at least 2,000 megawatts.

In addition to Massachusetts, the tract could serve three other states that are expanding their solicitations for clean energy.

In New York, Governor Cuomo announced a goal of procuring 2,400 megawatts of offshore wind, with the first RFP expected early next year.

Rhode Island Governor Gina Raimondo has announced a goal of procuring 1,000 megawatts of clean energy by 2020.

In Connecticut, Governor Malloy signed Public Act 17-144 last month, allowing offshore wind to be considered as part of a new RFP for clean energy resources, which would also include utility rate base fuel cells.

This can enable construction of approximately 200 megawatts of offshore wind.

The timing of the new solicitation will be at the discretion of the State Department of Energy and Environmental Protection, but it shows yet another legislative effort by a New England state to bring more clean energy resources into the region.

Additionally, earlier this week, the Connecticut Department of Energy and Environmental Protection published a draft of the state's updated comprehensive energy strategy.

The strategy focuses on five major themes.

They are: decreasing carbon emissions; increasing the supply of renewable energy, including expanding the state's Class 1 renewable requirements to 30% by 2030; and prioritizing low-cost grid-scale renewable energy investments; expanding energy efficiency initiatives, including procurement of energy efficiency as a resource; supporting grid modernization and accelerating electrification of the state's transportation sector.

We believe Eversource Energy is uniquely positioned to support each of these state policy initiatives.

With Connecticut, Massachusetts, Rhode Island and New York all driving policies that favor efficient offshore wind development, we expect significant interest in Bay State Wind's potential over the coming years, and we have begun to make early progress on siting.

About a month ago, the Federal Bureau of Ocean Energy Management issued to Bay State Wind the first approval of an offshore wind site assessment plan in the United States.

This will allow us to take critical measurements of wind and wave speeds over the next two years to prepare for project development.

Finally, turning to Access Northeast.

We continue to discuss the gravity of New England wintertime energy supply situation with policymakers in Massachusetts and New Hampshire, the two states that do not have legislation clarifying electric utilities' ability to sign natural gas supply contracts.

Brayton Point, the region's largest coal and oil fired generation plant, shut down permanently June 1. And the Pilgrim nuclear plant will shut down in less than two years.

ISO New England continues to express deep concern over the region's ability to meet both gas heating and electrical requirements during winter periods.

Later this year, ISO is due to issue a report on the challenges New England will face in future winters if no significant firm fuel capacity is available for the region.

While we are confident that Access Northeast remains the region's best option for adding needed natural gas pipeline capacity, we also know that the project's ultimate size and configuration will depend on what kind of solution our states want to pursue to ensure electric grid reliability and to integrate renewable power sources into the New England grid.

Because of that lingering regulatory uncertainty, we and our Access Northeast joint developers, Enbridge and National Grid, withdrew pre-applications from FERC last month.

FERC has a very busy calendar, particularly for signing of natural gas pipelines, and we thought it best to withdraw our project from preliminary review.

And so we are able to bring more certainty to the question of who will be the counter parties that will purchase long-term pipeline capacity from Access Northeast.

We expect most of the work that we have already done on the project can be used in a future refiled Access Northeast application.

We have no question that the region's wintertime gas supply situation continues to worsen, with generations, such as Brayton Point, retiring and more natural gas-fired plants being built and the region's homes and businesses continuing to install tens of thousands of new natural gas space heating systems annually.

However, we need state energy policy to be more consistent across the region, particularly in Massachusetts and New Hampshire.

We expect to refile a preliminary application with FERC for Access Northeast once we have a clear path to resolving current inconsistencies in policies.

Now I will turn the call back to Jeff for Q&A.

Thank you, Lee.

And I'm going to turn the call back to Sylvia just to remind you of how to enter questions.

Sylvia?

(Operator Instructions)

Our first question this morning is from Mike Weinstein from Credit Suisse.

Thanks, Lee, for that great update.

Maybe we could just talk a little bit about why -- like, why is it a full year delay for Northern Pass?

How come not the spring of 2020?

What equipment exactly is proving to be critical path items that extend the schedule at this point?

And also separately, how critical is winning the RFPs to keeping the project on track?

I mean, my understanding is that they're not -- it's not critical.

What happens if you lose?

I understand there's other opportunities in these other states that are -- will be coming next year.

But how critical is it to keeping the project on track?

Sure.

Just to get to the first part of your question, Mike.

If -- the HVDC converter technology is the critical path, along with the underground, what they call XLPE cable.

So those are cables that have no oil.

And those two components are the critical path.

And both HVDC converters and that particular kind of cable is in strong demand around the world.

There is long lead times for both of those.

Each HVDC converter, there's nothing on the shelf, so to speak, that you can use and you back-fit for a particular application.

Every design is a completely unique design.

And it's just the time that we've got from the manufacturer, ABB, of the cable and HVDC converters.

And it's really the limiting factor there.

So it's just where -- how much they have in the queue and where we show up in the queue.

It's really no more complicated than that.

In regards to the project, whether we win the RFP or not, we are committed to build the project and HQ is.

I have stated there are a lot of opportunities in all of these states for clean energy.

If you look at where the region is and the precarious position of the region absent a dedicated, firm fuel supply, particularly natural gas, you are going to need more firm energy like Hydro-Quebec has to offer into the marketplace.

You probably, I'm sure, have seen where the largest nuclear operator in the region is now inquiring through ISO what it would take to retire those assets, what that process looks like.

They haven't made a commitment to go do that.

But I think in any case, whether that's done now or later, all of those assets time out.

And if the region wants to meet its goals around carbon reduction and Class 1 renewable energy as well as clean energy, you will have more hydro coming in from Eastern Canada in Quebec to help satisfy that.

So we're confident that the project will get built irregardless of the outcome of this RFP.

Okay.

And in terms of the FERC transmission complaints.

Is this plan to refile, to revert back to the old ROE, has that been discussed with other interveners in the case?

Has -- what's your sense right now of how that's going to proceed going forward?

Is there going to be a settlement process that ultimately resolves where your ROEs eventually land?

Sure, Mike.

This is Phil.

The filing was done in consultation with the New England Transmission Owners because we needed to have a rate that we could bill customers.

And given that the decision of the DC court, vacated complaint 1, we needed to have a rate on file that we could start billing our customers with.

So this was a consultation and a filing with the New England Transmission Owners that was made in early June.

And as you know, there's really not a forum or a quorum at FERC at this time to review that.

So we have not changed our billing until we move through that process.

In terms of settlement, we've tried, we have.

In each of these complaints, there has been settlement process.

The traditional FERC process is to start that.

We have not, in any of those cases, reached any settlements.

So I guess one could always be reached in the future.

But I guess at this stage, we're awaiting a quorum so that the case can be reviewed and we can move forward.

And one last question.

On Aquarion, how far in the process are you right now at looking at further acquisitions of distressed assets that are out there?

Is this something that we should expect to hear within -- fairly soon after closing the deal, like, next -- early next year?

Yes, I can say, Aquarion is a private -- they're a privately-held company right now.

But if you look at their track record over the last many years, there's about a dozen different smaller, financially distressed systems that have been, let's call it tucked in under the Aquarion umbrella.

So that's about 11,000 additional customers.

There's 230,000 customers now.

Certainly, there's more of these types of systems out there as you get aging infrastructure, more requirements to -- for clean water, that type of thing.

So just given that kind of track record, I would expect that to continue.

So I mean -- if I just did the quick math, 11,000 consumers on 230,000 now, that's about 5% increase in size.

Is that sort of the opportunity on a dollar basis that you might be looking at as well?

No.

It's very fragmented.

Some of these system's maybe 5 or 6 customers.

Some could be 1,000 or 2,000.

So it's hard to say.

Certainly, you have to match up the need with the opportunity.

So the 11,000 over the last kind of 5 years is just an indicative number as to the process that's out there.

And I think if you look around the country, you'll see that this type of activity goes on.

Next question is from Paul Patterson from Glenrock.

So just to sort of follow-up on Northern Pass.

Is it safe to say that you guys are going to be participating in the upcoming capacity auction?

Is Northern Pass going to be participating in it?

Paul, this is Lee.

The capacity auctions, the participation in that will be determined by HQ.

And they're in the process of evaluating that option right now.

And I can't tell you what their conclusion is.

Well, let me ask you this.

If you don't clear it, how is capacity going to be provided with respect to the Massachusetts RFP?

Well, the RFP is not hinged on capacity, it's really all hinged upon the things like price suppression; carbon reduction; obviously, the cost of the project.

Those are the things that it hinges on.

So if it gets capacity as well, that's an added benefit to customers of -- in Massachusetts and into the region.

Right.

So you would think that it would be part of the value that the project would provide.

So it seemed kind of strange to me, I'm sorry, to be so slow on this, why capacity wouldn't be something that you guys would want to have value being reflected in terms of the project...

Yes, it clearly would be, Paul.

I just can't tell you exactly right now where HQ is on that.

But it clearly would be part of the value proposition for the state and the region.

Okay.

With respect to determination on MOPR, when would we find out how ISO New England officially will be treating Northern Pass and the issue of MOPR?

Well, one of the things that HQ has to do is to actually submit a formal request to ISO New England to have them evaluate Northern Pass vis-a-vis the MOPR requirements.

And they have not done that at this point.

Okay.

And then you mentioned that if the Massachusetts RFP doesn't happen, you feel there's enough opportunity out there which makes sense for the value of the project.

But I'm just wondering, do you think the project would proceed in the absence of some sort of contractual set up, such as the Massachusetts RFP or some other state sort of sponsor program?

Or that there's enough confidence that you just simply proceed with the project and hope to get something regardless, if you follow me?

I follow you, Paul.

I think where we are right now is we think our project has all the attributes that it will be the winning project in this RFP.

And if, for some reason, we don't win this RFP, we'll take a pause, we'll take a look, and we'll look at where the other states are in those RFPs and in that process.

And we'll make that decision at that time.

Okay, fair enough.

And then just finally, the sales growth, weather-adjusted year-to-date.

I'm sorry if I missed it, just really busy.

But I didn't see anything on that.

Could you tell us where, for just system-wide, you guys are in terms of retail electric salse growth year-to-date, weather adjusted?

Yes, the normalized, Paul, is down just less than a percent on a normalized basis year-to-date.

Next question is from Michael Lapides from Goldman.

Real quick.

Just trying to think about the offshore wind process.

Can you talk about what -- like, let's talk about the time line, both not just for the RFP responses, but then the DOE approvals for the tracks out in the ocean and then the kind of the other siting and permitting for where the line would potentially terminate in the U.S. onshore.

Like, how do you think about, cradle-to-grave, what the time line is from the RFP process to actually having an operating asset?

Yes.

Michael, this is Lee.

In regards to that, I think obviously, we've got a pretty good line of sight around the Massachusetts offshore wind RFP and the process.

And we've got time lines as issued inside of the draft.

And then it really becomes what is the time line from the Bureau of Ocean Energy Management, which falls under the Interior Secretary's office.

And there is -- I would call that kind of a work in progress, that they've got kind of a draft time line out there.

We will be meeting later this year with staff in the office of Bureau of Ocean Energy Management.

And we need to work with them.

And clearly, there's other stakeholders here.

There's a lot of offshore wind developers that will be working with the Interior Department as well to finalize what that process is.

But I think if this is, this is 2017, I think that it's realistic to see the first tranche of wind in service by the 2022, end of 2022, time frame, based upon the feedback, obviously, we have from DONG Energy, who's built a lot of this all over the world.

And so we feel the first part of this wind farm would come on in 2020 -- 2022, rather.

It's not like building a large power plant.

You string 6 of these things together and the first 6 of them show up onto the grid.

And then every time you add another 6, 6 more of them come on to the grid.

So it's kind of a phased-in.

And so you have early revenue production in that process.

Got it.

And Phil, you talked a little bit about your capital spending plan and budget.

And I know you're going to give more detail either at EEI or at the fourth quarter call.

But can you just kind of a rehash a little bit of that and maybe give a little more clarity, where specifically would you see an uptick in kind of traditional, whether it's transmission or distribution CapEx in 2018, relative to what your prior forecast showed?

Sure.

I guess I'll preface it by saying I think we have a very good line of sight even as we sit here today.

Without moving through too much time through the rest of the year, we still have our budget process to go through, et cetera.

But really, at this time, have a very good line of sight.

And just to remind you, too, that we've been repeatedly able to deliver these results.

If you think back to our February plan, we added $1 billion of capital from the previous plan that had been submitted.

So certainly, we have a track record to be able to deliver these results, and really with a focus on cost control that's unmatched in the industry.

So we can deliver the results, take cost out of the business, improve our reliability, provide great service to customers.

And these are all great aspects of our company.

So we do have an experienced team.

We have a strong balance sheet.

If we look at it, as Lee mentioned, there's going to be additional infrastructure needs, there's going to be likely more clean energy growth opportunities.

But to be specific about the things in terms of electric distribution we have in our gas distribution business, we have these reliability enhancement programs that help to improve that service reliability on both the electric side and the gas side.

We have aging infrastructure replacement and our gas expansion program in place that we expect to have incremental spending in both of those categories that is fairly significant in 2018 from our original estimate.

And as I mentioned, the water business at Aquarion.

Again, depending on the exact closing date of that, there is a robust capital spending program in there.

So those are really some of the major categories.

You could see others develop as we move through the rest of the year.

Got it.

And can you quantify?

Is there a way to quantify how much incremental CapEx would likely come relative to kind of the movement of Northern Pass?

What I can say is we fully expect to replace the spending.

In terms of the detail level and number, I'll have to hold off on that, but the short answer is we fully expect and have a good line of sight to replacing any movement of spending out of 2018.

Next question's from Shar Pourreza from Guggenheim.

Let me just touch real quick on Northern Pass.

I mean, obviously, Hydro-Quebec is active with the competing proposal.

And obviously, both lines have relatively strong attributes.

Let me ask you, assuming that you don't win these RFPs, when you think about future opportunities, is there an opportunity to partner?

Because most agree that TDI's not going away.

And then the other question is, is can you just touch a little bit on your committed to building the project whether or not you win the RFP?

Just how would that work sort of mechanically?

Yes, a couple of things in regards to your question on partnering.

Obviously, we think we're quite good on partnering because we've had a lot of partners between Enbridge and HQ and now DONG Energy.

And so we think we're good in that.

And should an opportunity to partner with these folks ever come up, we'll certainly consider that.

That's not out of the question.

But getting back to your second part of your question, yes, again, I think we'll win the RFP, the Massachusetts RFP really because our siting on both sides of the border is just about complete.

The other projects, they'll have to go -- particularly those that interconnect with Canada, have a 2- to 3-year process in which they're going to have to work through, and whatever their state siting processes are.

Our engineering work and design is essentially completed.

We have got our major contractors lined up.

We have firm bids.

We have firm place in the queues from manufacturers.

And again, building these things poses a lot of risk unless you have the very best contractors, and we have those, particularly with Quanta, who's done a lot of work for us.

And when you look at it, the Massachusetts RFP gives a special consideration for projects that are in service by the end of 2020.

And just the fact that Northern Pass going into service, that'd have about a 25% reduction in the electric sector CO2 emissions.

So we would be right where they need to be by the end of 2020.

So it's got all the right attributes.

And just to repeat what I said before, Shar, we would -- if, for some reason, we did not win this RFP, we would sit down with our partners, HQ, assess where we are vis-a-vis the other states, and then make that decision to proceed.

But I think both partners believe the project will get built for all of the reasons that I just covered.

Got it.

That's actually very helpful.

Let me just, on Aquarion.

I know you prepared remarks, you talked about the attribute.

Again, it's located and doing business kind of locally.

Obviously, areas around the New England, especially on the water infrastructure side, are very prone for acquisitions on the muni, especially like in states like New Jersey.

So when you sort of think about growth opportunities around this business, is there an opportunity to grow outside of New England?

So could we eventually see this entity start to acquire munis in surrounding regions where you have similar legislation?

Or are you pretty much focused on remaining within the New England region?

Yes, Shar.

This is Phil.

I think that -- so first of all, I'll say we're just starting our regulatory approval process.

So our primary focus in the near term is to effectively move through those processes in the various states and get the approvals and move forward.

Certainly, as we move forward into that business, then we'd have to look at all the opportunities that present themselves, just like we do in all parts of our business.

The projects that Lee's talked about, you have to look for those and you have to see what the opportunities are and move on them if they're in the best interest of the company.

So there's no reason to think we wouldn't do the same thing in all aspects of our business.

So right now, I'd say our focus is on getting the deal across the goal line in terms of the regulatory approvals.

But in any aspect of what we look at, we're always looking for opportunities to grow the business, provide great service, produce returns for investors and results for customers that put us in the top quartile.

Next question this morning is from Steve Fleishman from Wolfe.

Sorry, it's been a distracting morning, so a little bit of repetition here.

Just on -- I saw some local stories where -- does it look like the September 30 date is also going to be delayed for approval in New Hampshire?

Yes, this is Lee.

There is going to be a SEC pre-conference meeting, I think, on the 9th of August that will look at the final phase of the hearings.

So it will be the third one.

And it will lay out the schedule to the end of the hearing process.

So right now, I don't have anything other than the end of September time frame for you.

I think all of our witnesses will be done in their testimony by the end of August.

And then it becomes the witnesses, the intervener's witnesses, for cross examination.

Obviously, most of that gets done by us.

We will determine who we want to cross and who we don't want to cross and how we optimize that schedule.

And then it's really written briefs by all parties.

And then there will be a deliberation by the SEC, and that will be public deliberation.

And a decision will be made.

It would be an oral decision which will be followed up by a written decision that would be somewhere between 30 and 60 days.

So all of that, we believe, still falls into the time frame that basically says that we will have the final EIS, the record of decision from the DOE, the SEC decision, the presidential permit, by the end of the year.

All of that tees up us for a essentially third quarter 2020 completion of the build-out, testing.

The remainder of the year, begin service for this winter.

All of that supports.

Okay.

So, let's say -- just sorry.

But just let's say the dates, when we get them on August 9, are extended.

Is it -- you're assuming you're going to have a final order in New Hampshire by year-end.

So we would have to kind of measure against that, I guess.

Yes, yes.

Okay.

And you feel good.

And the other pieces fall right in place with that.

Okay.

And one question on the Northern Pass kind of replacement capital that you say you'll come out with.

Should we think of that as more moving forward capital that was in the plan in other businesses that was going to be in later years, moving that forward?

Or should we think about it as more actually just net new capital, new projects?

Yes, I'd say, primarily for the most part, it'll be new.

So there could be some movement, but I would expect that, that would be the smaller portion of it.

Primarily new.

Next question is from Caroline Bone from Deutsche Bank.

Most of my questions have been answered.

I just wanted to follow up.

And I also -- I feel like it's been a busy morning, so I apologize if I missed this earlier.

The benefit you guys saw in Q2 from that renewable fund investment, is that something that we should expect to continue?

Or is that some sort of a onetime gain?

Can you just elaborate on that a bit more?

Sure, Caroline.

I wouldn't consider it a onetime gain.

It's been something that's been in our portfolio for many years.

I'd say what was unusual was the size of it was probably higher than had been the case in the past.

So we don't expect it to be significant going forward.

Next question's from Praful Mehta from Citi.

So actually, I was struggling a little bit on the water side.

You've talked about acquisitions as one possible opportunity to grow the water business.

But if you're buying at multiples that are at the 25x, 26x or whatever, the water business transactions get done, where do you see the synergy?

Or where do you see the value-creation opportunity that would justify that kind of multiple?

Yes, Praful.

As I said, in terms of the operations in the asset of Aquarion, they're a very well-run, well-respected organization.

Have a #1 in J.D. Power scores for their category, are focused on growing the business.

So I think there are growth opportunities that do exist in the water business.

As I said, the small, distressed systems are a growth opportunity that currently exists.

And we see -- if you look at the water business in terms of the water business versus the generation business that we're exiting, as I said, you have a business there that has no growth and is declining vis-a-vis a business that you're replacing that with that has some potentially significant growth opportunities as we move forward with aging infrastructure and the like.

So we see it as an excellent opportunity and certainly a good strategic fit.

Got it.

Fair enough.

So in terms of size going forward, what proportions should we think about?

Is there a goal in terms of how much of a potential rate base or proportion of rate base of the consolidated business you want the water business to be?

Or should we look at it as a much smaller part of the whole business?

Where do you see, I guess, the water business going, longer term?

Yes.

Certainly, if you look at the size of the existing generation business, it's about 3%.

If you look at the existing -- if you just take Aquarion, it's probably in that same general ballpark.

I can't give you a specific targeted number today, but certainly, we do expect that number to grow over time.

Next question is from Travis Miller from Morningstar.

Just real quick.

Following up on Aquarion.

I was wondering if you could discuss a little bit your regulatory goals, either through the approval process or in the subsequent 1, 2, 3 years in terms of things like allowed ROE's, cost riders, other cost recovery.

Just anything that comes to mind, things that were in your plan in terms of making the acquisition, regulatory side.

Sure, sure.

Absolutely.

As I mentioned, in my remarks -- I'll focus on Connecticut because 90% of the business of Aquarion is in Connecticut, and I would consider, certainly, Connecticut is a state that we're familiar with at Eversource.

And Aquarion, obviously, is very familiar with from the years of dealing in that regulatory space there.

The water regulation is constructive in Connecticut.

There are trackers for infrastructure programs.

There's the so-called WICA program.

That's not my Boston accent, that's actually WICA.

And decoupling programs that, just like the electric industry, that decouples usage from the bill.

Distressed system.

If you buy distressed systems, you're allowed to put that into rate base or get a higher ROE allowance.

So certainly, the regulatory framework is constructive.

The ROE in the water business there is at least equal to a better than what we have in our electric and gas business in Connecticut.

So certainly -- and then if you look at it, you really have -- I think local ownership really means a lot that if you look at the rationale for the sale of the company, it was strictly related to a fund that Macquarie had that was -- needed to be dissolved.

And that could have gone in a lot of different directions.

So having local ownership, where we expect to keep the existing operations pretty much in place.

As I said, we're not in the water business, they have a great track record for operations.

So all those things, I think, will be favorable.

Next question's from Mike Weinstein from Credit Suisse.

Guys, just a couple of quick follow-ups.

On Steve's question regarding delays in the -- and possible approvals by September 30.

Let's say the final approvals don't come until January instead of December, the year end.

Like, at what point does the project get moved into 2021 for completion?

Like, when is the last possible moment you can get the Presidential Permit and start construction and still remain on schedule for end of 2020?

Yes, Steve, this is Lee.

Mike.

Mike.

Excuse me.

Right now, we've got our schedule set up that we have all of our permits in hand such that we can get ready to go for construction in the early part of the year.

And is there some slack in those schedules?

Sure.

Is there on all schedules.

And to the extent that if it did get delayed, we'd to have to go back in, we'd have to assess the slack and any ways to optimize the schedule.

And we would have to make that call at that point in time.

But we're really geared up to get all of these approvals by the end of the year and that meets our scheduled in-service date in the third quarter of 2020.

And we'll just have to assess that as we go.

There is some slack in the schedule.

Okay.

I mean, I guess one thing I'd be concerned about is that the vendors might -- if the delay is too long, the vendors might say, "Hey, we have other customers that would need this equipment..."

No, that's a fair statement because this equipment is in demand all over the world.

Right.

A quick follow up on that onetime gain, that $0.04 gain in other income.

Is that -- was that part of the 2017 guidance?

Is it -- is this something that is an investment that can continue to pay off in future years?

Or is this really just really a onetime payment that was not included in the guidance?

Yes, Mike.

It wasn't really -- it's not a $0.04, it was really a couple of cents that was in the quarter.

So the total change in that parent line was $0.03 to $0.04, but the incremental per share number related to that investment was just a couple of cents.

And really, the reason it looks different is last year was a $0.01 loss.

This year, it was a couple of cent gain.

So that, it's a $0.03 swing.

So it's in there, it's always in the guidance because we do have that investment.

And as I said, it generally is plus or minus $0.01 in that category.

But we have other reconciliation items.

I mentioned the transmission reconciliation, that's always in our guidance.

That could go plus or minus.

We reconcile our energy efficiency programs, those could go plus or minus.

So it's really part of the ebb and flow.

Okay.

It's not -- there isn't some ongoing $0.02?

No.

There was -- the reason it was a little bit higher this year was there was a kind of a special contract that one of the investments had in 2016 that wasn't there the prior year.

So no, I would say it's not something that we would plan on going forward.

Okay.

Also, it sounds vaguely like there's some reserve of capital projects that sits out there.

That...

No.

No.

No.

When you say reserve, what are you referring to, Mike?

Sorry about that.

Oh.

I'm sorry.

Can you just repeat the question?

I think you may have gone on mute.

I'm sorry about that.

Yes, I'm just wondering if -- it sounds like there's a reserve of capital projects that sit out there that could be brought in to bear when there's a delay in other projects, that there's things being spent.

When projects are higher priority now, like Northern Pass, you put off other things, and those things can be brought forward and brought into the plan when there are delays.

So is this something that -- should we be expecting a big increase in the capital program at EEI this year?

Well, again, we do announce the capital and our guidance in the February time period.

But just like, I think, any effective financial and business planning operation, we don't just do it one time a year.

We're continuously looking at what are our needs for our customers?

What do we have on the schedule?

Sometimes, a project gets a little bit delayed in siting but another project has progressed faster than we thought.

So we're not creating new activities to do.

We're developing a capital program that is responsive to the needs of the region in terms of reliability, responsive to our customers.

We're putting capital, and we -- our O&M is all directed at providing great customer service, top-tier reliability, those types of things.

So -- but there is an ebb and flow in projects and we don't just look at them once a year.

So there are projects that do move.

Some move faster, so you can advance them; some move slower, so they have to go into another year.

But there's not a reserve out there that we're picking from.

Let's move on to I think is the last question today.

[Joe Zhu] from Avon.

Joe, you there?

Actually, it's Andy.

Just one last question on Northern Pass.

Did you guys have -- you guys ever talked about -- because I guess, through the RFP, you're saying -- or just in general, that you have 60 miles of undergrounding budgeted.

Is that correct?

Yes.

All right.

And then once the Site Evaluation Committee comes out with their final ruling some time this year, is there, like, a number or -- meaning CapEx-wise or mileage-wise on the undergrounding that's kind of make or break?

Andy, this is Lee.

I guess you could say that, obviously, by the nature of this process, it's a competitive process, and really don't disclose all the parts and pieces of the cost.

As I said earlier, we have now firm contracts and places in the queue.

Important to note that the Department of Transportation has accepted our plan for undergrounding.

The Department of Environmental Services has accepted the project as is, as designed.

And so those are the two key agencies in New Hampshire that issued the reports around the viability of the design.

And so we're quite confident in that design, and we don't believe that in any way, there is a justification to do more than 60 miles.

So we think in and of itself, we're in a good place.

I understand that, but I'm just saying, is there a -- well, I guess the point you're making, just before I ask my question, is that based on those two agencies, you don't think the SEC is going to ask you to underground more.

Is that your point?

I can't speak for the SEC, obviously.

The agencies, there's members of -- the heads of those agencies sit on the SEC.

And the agencies themselves have provided final supporting reports that support the design as is.

But clearly, the SEC members vote independently.

Okay.

And but is there -- but I guess because of competitive reasons, you're not going to kind of put out a number or a mileage number or anything like that, that would make you or HQ feel uncomfortable to move ahead on the 60 miles that have been stated already.

Yes, I think that's fair to say, Andy.

Okay.

That's fair.

And then just as far as how that relates to the Massachusetts RFP, because I'm not that familiar with the process.

So when you bid into the RFP, the amount of undergrounding, is that part of the kind of the economics of the bid or not?

No.

No.

Actually, it isn't.

You're basically going to bid a project in that has a number of attributes.

Clearly, it's going to be the cost of the project, it's going to be the deliverage cost per megawatt hour of the project and the energy, right?

So you end up with a total cost, and that has to be competitive.

It's going to be does the owners have site control?

Do they have the requisite experience in building these?

Do they have the financial ability to do it?

What -- how much risk are the developers asking to be placed on the EDC customers?

And so forth.

And exactly when will it be in schedule?

What are the attributes, the operational attributes in terms of things like deliverability of the voltage and so forth?

Does it have flex-start capability?

Which hydro does.

Does it have the ISO New England approval?

So they're going to look at all of those things and they'll have a grading process of 100 -- approximately 100 points.

And they'll score each project in accordance with that grading process.

Okay.

I understand.

So really in a sense, the undergrounding affects the economics of the program, but it's really more for you guys relative to what it's going to cost the rate payer or the customer or the consumer through this Massachusetts RFP.

Yes, that's true, Andy.

All right.

That's the last.

And I think some folks have already moved on to the 10:00 calls.

Thanks for joining us this morning, and please call me if you have any follow-up questions.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.