Avangrid Inc (AGR) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the AVANGRID Third Quarter 2017 Earnings Conference Call.

(Operator Instructions) As a reminder, this conference is being recorded.

I would like to introduce your host for today's conference, Patricia Cosgel.

Please proceed.

Thank you, Terrence, and good morning to everyone.

Thank you for joining us to discuss AVANGRID's third quarter 2017 earnings results.

Presenting on the call today are Jim Torgesrson, our Chief Executive Officer; and Rich Nicholas, our Chief Financial Officer.

A team of AVANGRID officers will also be participating on the call to answer your questions.

If you do not have a copy of our press release or presentation for today's call, they are available on our website at www.avangrid.com.

During today's call, we will make various forward-looking statements within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995 based on current expectations and assumptions, which are subject to risks and uncertainties.

Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in AVANGRID's earnings news release, in the comments made during the conference call, in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our website, avangrid.com.

We do not undertake any duty to update any forward-looking statements.

Today's presentation also includes references to non-GAAP financial measures.

You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of non-GAAP financial measures to the closest GAAP financial measures.

With that said, I'll turn the call over to Jim Torgesrson.

Thanks, Patricia, and I want to welcome everybody to our third quarter call.

With us today besides Rich and Patricia and the entire IR team, we have Bob Kump, who is the CEO of our Networks business; and Laura Beane, who is the CEO of our Renewables business.

With that, AVANGRID really had another good quarter of consistent financial results.

We're really on track to meet our 2017 financial and operational targets.

And we're also executing very well on our long-term plan.

Now, look at the financials.

First off, for the third quarter, we had net income of $99 million or $0.32 a share, which on -- for an SEC reporting basis was down 9% from the third quarter of '16.

And we had 9 months results of $458 million or $1.48, which was up 8% on an adjusted basis, and the adjustments are really related to taking out the Gas Storage business, mark-to-market earnings and losses, some restructuring charges, which the initial ones we had and then a gain from some of the investments and impairment in 2016, so to put that in perspective.

With that, our third quarter adjusted net income was $125 million or $0.40 a share, which was up 11% over 2016 on a comparable basis.

And for the 9 months, we were at $494 million or $1.60 a share, up 14%.

And we're continuing to execute on our strategic plan.

We're on track for our 2017 investments.

Actually, we're up about 39% to $1.6 billion for the 9 months ended in September.

Much of that increase is in our Renewables business, but also a good portion in Networks as well.

We're executing on our -- adding PPA.

So far this year, we've added 487 megawatts of new wind PAs, which includes 86 megawatts which were signed in the third quarter.

And we continue to add to our Renewables pipeline.

We'll talk about that in a minute, but we're now up to an 8-gigawatt pipeline, which is an increase of 0.9 gigawatts just in the last quarter.

We filed a rate settlement with Southern Connecticut Gas with the Consumer Counsel of staff supporting.

And it was filed with PURA, and they will then make a decision in the not-too-distant future, have rates by the end of the year.

We're expecting a decision in late November or early December.

It had a 9.25% ROE on 52% equity.

Now one of the things I'm particularly proud of is we actually have a very extensive suite of policies and procedures that form the basis for our governance, our ethical and compliance programs.

And also, we have the best practices we've gathered from U.S. and from internationally.

And AVANGRID's core values of ethical principles, good governance and transparencies are being recognized now for the second year in a row as we were named the North American utility with the best corporate governance by Ethical Boardroom publication.

We're very happy with that result.

Now turning to Page 6. You can see the things we just mentioned.

Net income in the third quarter was slightly lower, but there was improvement for the 9 months.

Now net income and earnings per share reflect the inclusion of Gas Storage, all the things I said that weren't included in the adjusted numbers.

They also reflect a small restructuring charge -- initial restructuring charge of about $0.01 a share and this is really related to our Forward 2020 program and looking at some voluntary separations that we initiated in the third quarter.

Now turning to Page 7, where we get to the adjusted earnings.

The adjusted net income improves in the third quarter, as I said, up 11% on the quarter both in earnings and earnings per share, as we'd guess, and then 14% for the year-to-date.

As part of the -- the reason for the adjustments, we've excluded the Gas Storage business.

We are continuing to evaluate that business and expect to finalize a decision by year-end.

Now the third quarter, just so to put in perspective, historically, it's the least amount of production from the wind resources and this third quarter was even below that where we would consider normal.

But we did -- we have been implementing best practices and cost management across all of our businesses, and so the new rate plans in Networks and then the cost management we've implemented help to offset the low wind resource that was really 5% below our normal and that impacted the year-to-date by about $0.06.

Within the quarter, it was $0.02 off of 2016, but in 2017, we actually did added another 208 megawatts from our Desert Wind project, which probably added $0.01 in itself.

So really, wind had an effect of about $0.03 a share in the third quarter alone.

Now turning to Page 8. When we look at our capital spending, which are supporting our Networks and Renewables growth, we're looking at spending about $2.2 billion for this year, $900 million in Renewables and $1.3 billion in Networks.

And you can see through the first 9 months, we were at 1. -- almost $1.6 billion, almost evenly split, a little more, about $100 million more in Networks than in Renewables.

And as I said, Renewables has a number of projects going on.

And you can see that on the next page, on Page 9. We have 5 projects that will be completed in 2017 that will add 590 megawatts, 56 megawatts of solar and 534 megawatts of wind.

The Gala solar project, with 56 megawatts and being sold to a large C&I customer, is running now with test energy being implemented along with El Cabo, the 290 (sic) [298] megawatts.

Those are in commissioning mode where we're generating some test energy.

And then the Tule, Twin Buttes and Deerfield are all in the process of putting in the turbines, and those will be fully operational by year-end.

In our fact book and our operational statistics, we showed 6,287 megawatts of generation capacity, really about 500 -- 5,900 of it is running full day-to-day.

The balance may be in test mode, and we get some generation, but I don't want you to count on that going for the full quarter because we only have 509 -- 5,900 megawatts that are operating day-to-day.

So turning to the next page, Page 10.

You can see our Renewables additional pipeline we've added.

In the pipeline projects, we've added 600 megawatts of wind and 300 megawatts of solar, and those are spread out across the country in Wyoming, Oregon, Michigan -- or Minnesota, I'm sorry, Illinois, New York, Maryland and Connecticut.

It does not include any of our offshore wind in that pipeline.

And all the wind projects we have are getting 100% PTC.

This is very important.

The projects that we have that are going to be done this year, obviously, have 100% PTCs, and the ones that we're developing are as well, Montague in Oregon, again, being sold to a large C&I customer, it's 201 megawatts.

That will have a COD in 2019.

Then we have a Texas Wind Project, which we signed with Austin Energy for 200 megawatts.

And the latest one, a new PPA with a major footwear and apparel company of 86 megawatts also in Texas, which will COD late in '19 as well.

So we're looking at our long-term plan.

We now have secured -- of the 1,800 megawatts in our plan, 60% or 1,087.

So 590 under construction, 497 that will be built, actually Montague is already starting initial construction already.

So we're moving along very well with our plan, and we fully expect to have the 1,800 megawatts by the time the end of 2020, and hopefully, more than that.

We also have, on Page 11, some of the Networks capital projects, and these are fairly significant as well.

We have -- are going to go live on our Customer Smart Care Data System in Maine, that's a $57 million project, that's going to go live October 30.

It's already been approved by the Maine PUC.

It's in [raise], but we've been deferring the recognition of it until it actually goes live and it's used and useful.

We also completed earlier this year the Ginna Retirement and the Auburn Transmission projects, which were about $250 million of transmission projects.

The Rochester Area Reliability Project, that's a $250 million project, which will go live in 2020.

And we have T&D upgrades in Connecticut on the Metro-North Railroad Corridor, that's a $175 million project that will be live again in 2020.

We have gas distribution lines replacement and expansion.

Much of the replacement in New York, which is about $280 million-or-so and then in Connecticut another $290 million in replacing bare steel and cast-iron pipe.

So in those 2 areas, we're going to spend almost 600 -- about $570 million on replacing bare steel and cast iron and then some expansion.

And we also have an LNG enhancement in Connecticut on 2 different LNG sites.

We have the Lewiston Loop, which will be operational in -- next year in 2018, which is another $70 million project.

So you're looking at our highly likely capital expenditures, which are the advanced metering infrastructure and the DSIP, Distribution System Implementation Plan, that will probably commence probably mid-2018.

We're waiting for the commission to give us the determination or approval on the AMI.

But without those 2, we have 91% of our capital expenditures are secured for the Networks business and 9% are considered highly likely, which we feel pretty strongly will happen in -- starting in 2018.

Now turning to Page 12.

We have -- in New York, we're working on a collaborative Earnings Adjustment Mechanism and working with the staff on negotiations, and those are ongoing.

We expect that to be implemented in 2018 and that provides incentives to -- that would actually increase the ROE if the targets are achieved.

The determination of AMI, as I mentioned, was deferred to late 2017 so we expect the decision now in the first half of '18.

In Connecticut, Southern Connecticut Gas, we have a 3-year rate settlement with the OCC and the PURA Prosecutorial Unit that was filed with PURA on October 16.

It was amended slightly for some minor changes, I think, the total may be $100,000, but with the cumulative revenue increase, it's going to be about $11 million.

Importantly, the ROE is 9.25% at 52% equity.

Rate base is going from $544 million to $618 million by December of 2020.

And the capital plan does include the Distribution Integrity Management Program, which allows us recovery of capital spent to replace the bare steel and cast-iron pipe in the succeeding year.

And now we're at a 20-year replacement cycle and the cost recovery is actually the same and very similar to what we have at Connecticut Natural Gas.

It also adds revenue decoupling, which is required by legislation.

So also, in the last week, Connecticut PURA opened a docket to review gas LDCs, their supply portfolio, asset strategies and practices.

Now, I think, many of you know the environmental defense fund put out a white paper that talked about the practices in Connecticut of the 2 companies, AVANGRID and Eversource about releasing their capacity, and I want to spend a minute on that.

In Connecticut, we have an obligation to serve, we have an obligation to make sure our gas customers have their gas 24/7 365 days out of the year.

And we are also the supplier of last resort.

So we have an obligation to provide gas and we also have a very strict code of conduct for our employees that require all employees to follow all the rules, laws, legislation, in particular, those of PURA and in the FERC, and I'm confident our people are doing that.

Now what we will be doing is looking at making sure that we're following all the rules, which we believe we are, and we'll cooperate with PURA in their review.

We will be working with them directly.

And if there are opportunities to modify the way the rules are today, we will certainly have discussions about that.

But as far as we're concerned, we're doing everything we need to do to make sure our customers have the gas supply when they need it even on the coldest days.

And so that's the objective we have.

At FERC, the quorum has been restored, as I think all of you know, with the Senate confirming Rob Powelson and Neil Chatterjee of the nominations of Rich Glick and Rob (sic) [Kevin] McIntyre as, supposedly, as Chair are still awaiting for the full Senate to approve it.

In the ROE complaint #1, FERC rejected the New England TOs filing to begin billing at the prior 11.14% ROE, and we said we'd start billing 60 days after the FERC quorum.

The FERC denied that request and noting that the ROEs will be addressed in the order on remand.

Complaint IV, the FERC Trial Staff filed testimony.

ALJ decision is expected in March.

And on October 5, the New England TOs filed for FERC to dismiss, actually, all the ROE complaints as not being in compliance with Section 206 requirements, as was determined by the D.C. Court of Appeals.

So turning to Page 13.

We are executing on our commitment to deliver the 8% to 10% compound annual growth rate through 2020.

The earnings performance in the third quarter was impacted by low wind resources, but because of our cost management, our Forward 2020 program, we were able to mitigate much of that.

And we will continue working on that.

It just shows the ability we have to get -- to be flexible and to operate the business so that we are working to hit our targets.

We are reaffirming our '17 guidance, adjusted earnings per share outlook of $2.10 to $2.35.

And we are executing on opportunities in our core business.

We have new and existing wind projects.

Our 2017 investments are really in line with expectations.

And our 3-year rate plans in Connecticut and New York are giving a basis, along with the FERC formula rates that give us greater than 80% rate certainty for our company.

We're implementing the best practices through our Forward 2020 program, and we continue to anticipate raising the dividend in 2018.

Looking longer term, we see the continuation of developing the onshore renewables and a lot of the transmission projects that we see for the potential for long-term growth, some of it through the Massachusetts Clean Energy RFP and the New York Transmission & Renewables solicitations, but also with the offshore wind RFP that will be in Massachusetts.

So we feel very good about the future and the -- our opportunities to take advantage of those things that are coming along through the pipeline in the not-too-distant future.

So with that, I'm going to turn over to Rich Nicholas who's going to present our financial results in a little bit more detail.

Thank you, Jim, and good morning, everyone.

Thanks for joining us today.

I'm now on Slide 15 in the presentation.

And as Jim mentioned, the third quarter GAAP net income is down 9% versus last year, but the adjusted net income is up 11%.

And for the 9-month period, GAAP net income is up 8% and adjusted net income is up 14%.

Our results for both the third quarter and year-to-date have benefited from the multiyear rate plans at some of our Networks companies as well as new capacity in the Renewables business.

However, as mentioned, the wind resource has been below average, but we continue to focus on operational excellence to deliver results despite the low wind resource.

Moving to Slide 16.

As you can see, our third quarter and year-to-date performance has been primarily driven by the Networks results for both net income and adjusted net income.

And I'll review the business segment results on the following slides.

So turning to Slide 17 to look at the 9 months results.

Networks' adjusted net income was up $53 million versus 2016, driven by best practice implementation, the new rate plans and a $6 million after-tax benefit from moving what was the UIL Holdco debt up to corporate.

In addition, the first 9 months include a $5.2 million after-tax charge for sharing in New York, which represented the portion of our earnings shared with customers for the rate year -- first rate year as we were able to earn above the allowed return in that period.

For the Renewables segment, the 9-month adjusted net income increased $11 million versus 2016.

And the new capacity in 2017 resulted in a slightly higher wind resource for the period, although still below normal for the first 9 months of the year, which had an impact of approximately $0.06 a share.

We also experienced higher earnings in our energy management part of the business by optimizing our assets in the Northwest part of the country.

At the Corporate segment, adjusted net income was down $4 million versus 2016, impacted by the transfer of the UIL debt that provided a corresponding benefit to the Networks business.

The consolidated tax rate through 9 months was approximately 31% on a management reporting basis, which includes production tax credits and gross margin and excludes them from income tax.

We expect the full year adjusted effective tax rate to be around 33% to 34%.

And although the noncore business Gas Storage net income for the 9 months increased $11 million compared to 2016, primarily due to mark-to-market changes in the period.

So now moving to Slide 18 for the third quarter segment results.

Here you can see Networks adjusted net income increased $31 million versus 2016, up to $106 million, again, primarily due to the new rate plans that have been discussed and best practice implementation as well as returns on equity investments in the GenCon and New York Transco as well as the aforementioned transfer of the UIL debt up to corporate.

Renewables adjusted net income was $17 million, a decline of $9 million compared to last year third quarter, primarily due to lower wind production of $7 million and lower prices of about $2 million, with improved -- offset with improved energy management services of about $4 million.

Note that the third quarter is the seasonally lowest quarter for the Renewables business, and we've got a graph later on, on Slide 21 to show that.

Turning now to Slide 19.

The key drivers of our performance for the Networks business which really delivers high-quality earnings growth with rate certainty and stability, again, due to the multiyear forward-looking rate plans, revenue decoupling, various tracking mechanisms.

And for UI and Central Maine Power, our transmission rates, we utilize the FERC formula rate process, which provides for annual true-ups.

The New York rate plan continues through May of 2019.

The United Illuminating plan goes through December of 2019, while the proposed settlement we have with Southern Connecticut Gas will be effective through December 2020, if approved.

So we are currently evaluating the need for the next rate filings for Connecticut Natural Gas, Berkshire Gas and Central Maine Power.

And we're fully committed to continuing our Forward 2020 program to implement best practices.

Looking now at Slide 20 for the Renewables business, the primary drivers there in the 9 months include increased capacity of 524 megawatts to 6,287.

As Jim mentioned, some of those megawatts are operating in test mode and not fully in service yet, but will be by the end of the year where we expect another 218 megawatts to come online.

And while the wind production was up slightly for the 9 months compared to last year, the load factor decreased 3% as new capacity that's not fully online for the full period or just in test mode impacts that calculation.

We did see our average PPA prices decline 3%, offset somewhat by increases in REC pricing.

And all-in, our pricing is down just 0.3%.

The average PPA price at $55.80 is consistent with our long-term outlook of $56, as we have plan for certain PPAs to roll off while others have escalators in them over the period.

Now turning to Slide 21.

As I mentioned, here is the seasonality of the wind, the third quarter typically being our lowest.

The black line represents the average of 2011 to 2014.

And as you can see, the dark blue bar on the right of each quarter is 2017 and is below what the average has been.

Moving now to Slide 22.

We continue to execute on our plan and move forward with multiple projects under construction in Networks and Renewables.

Our cash CapEx year-to-date has grown to $1.7 billion.

We continue to have solid cash flows from operations that fund our growth of about $1.3 billion of this for the 9 months in 2017.

And the difference between cash from operations and CapEx is being supported by our short-term credit facilities for now.

Moving to Slide 23.

Looking at our credit profile, our net debt is now $6 billion.

We have very stable credit ratings, BBB+ and Baa1, with strong metrics of 2.9x net debt to adjusted EBITDA and 28% net leverage really giving us the flexibility to fund the growth that's in our long-term plan, but also providing us with the capacity to pursue the transmission and onshore and offshore renewables that Jim has mentioned.

So looking at Slide 24, our outlook for the rest of this year.

As Jim mentioned, we affirmed consolidated adjusted guidance of $2.10 to $2.35 per share.

However, we are adjusting the business segments to reflect the performance to date and the expectations in the fourth quarter really due to the below-normal wind resource.

So looking at the subsegments.

Networks guidance is actually being increased by $0.02 on both the lower and upper ends of the range due to the implementation of the best practices, while Renewables is being reduced by $0.05 on both the lower and upper end of the range due to the below normal wind, offset, again, by best practices as we look to implement those across the enterprise.

Corporate is also being increased by $0.04 at both the lower and upper end of the range due to best practices as well as a slightly lower-than-expected effective tax rate.

But the outlook does assume a normal wind in the fourth quarter and that we complete the projects on time as expected.

So with that, I'll just say, look forward to seeing many of you at the EEI Financial Conference in a couple of weeks, and I'll now hand the call back to our operator, Terrence, for questions.

(Operator Instructions) And our first question comes from Julien Dumoulin-Smith from Bank of America Merrill Lynch.

Just a couple Networks-focused questions, if you can.

First, on New York, I'd love to hear how the Earnings Adjustment Mechanism discussions are ongoing.

I know in the last call, you specifically called it out on negotiations.

Where did those stand?

And then secondly, if you could talk a little bit more on the FERC ROE conversation.

What are your expectations in terms of ROE and your specific plans around how you intend to book it going forward?

And then also with respect to the FERC transmission on the Western New York pit, what does that say?

And how are you thinking about the project award there?

Yes, let me deal with the ROE.

We've been booking at the 10.57% and we will continue doing that, which is what FERC has determined.

So that -- we will stick with that until FERC tells us something different.

And Bob, you may want to address the other parts?

Sure.

As relates to the Earnings Adjustment Mechanism, we pretty much settled on the metrics that we will be measuring to determine whether incentive is earned and I've talked in the past that those tend to focus around energy efficiency, peak shaving and our success at hooking up DER on our system.

The area that we're still working on is the value of those incentives.

You'd recall that in the DSIP Track Two order, it was determined that companies could earn up to 100 basis points.

To date, if you saw, for example, I think, ConEd received something in the range of 30 to 40 basis points so that's the piece that we're still negotiating in terms of the value of those.

I will say that this is a priority for staff, as Jim mentioned.

They want to make sure that these are up and running for calendar year '18.

So we will continue to work diligently to wrap up negotiations over the next couple of months.

And on Western New York, obviously, it was disappointing that we did not win that piece.

I guess, while I'll say at this point is lessons learned, there was a couple of issues in the end that were focused on in terms of the structure of the winning bid versus ours, that we'll learn from and move forward.

Got it.

Excellent.

And then just to be clear on the EAM stuff, just coming back to New York.

This would be for full year 2018 impact, one way or another, in terms of implementation so we should look for data points here shortly on how these conversations are going to play out?

Correct, that's correct.

And one other thing that I failed to mention on the Western New York, just to remember that, that was not in our numbers, so still disappointing nonetheless.

And our next question comes from Greg Gordon from Evercore.

A couple of questions.

First, when we think about your -- the cost optimization initiatives that you've really started to just roll out, are we looking at -- I mean, I think about 3 business segments, the corporate parent, the utilities businesses and IBERDROLA and Avangrid Renewables.

Are you expecting to see demonstrable improvement in costs in all 3 businesses?

So when we think about earnings drivers at the utilities, do you still see opportunity to see improvements in ROEs given the sharing arrangements or earned ROEs you have?

And then what jurisdictions for a second, do you think there is an opportunity to improve the overall cost profile at Renewables?

And then are there also sort of corporate parent benefits?

So when I think about modeling over the next 3 years, the cost profile of the business, in which segment should I be focusing on your most -- sort of your biggest opportunities?

Yes, Greg, I would see that where it's going to shake out is Networks will have it and again, we've said all along, we want to be able to get into the sharing ranges, and that's one of the mechanisms we'll use to do that.

I also see it at Corporate, and we'll be looking at some of the corporate -- all of the corporate areas, as a matter of fact, to evaluate how do we get as efficient as possible and then Renewables as well.

And keep in mind that the corporate charge -- Corporate gets allocated back to Networks and the Renewables so it will flow through that way.

But everything -- it's across the board, and keep in mind Networks is 70% of the business, 70% to 75%, so that's probably where bulk will be, but Networks, Corporate and then probably Renewables to a little lesser extent.

Renewables is growing, and we're adding a lot more so -- lot more megawatts.

So we have to be able to operate those, but we also are looking at how do we do it as efficiently as possible so everyone's involved in the Forward 2020 program.

Great.

My second question is, I know you're adding a substantial amount of wind capacity.

Hopefully, you do beat your modest target for 2020.

And we know that you've given an assumed decline in weighted average PPA price over the period.

Does that fully bake in the expectation sort of algebraically that the fact that new contracts are obviously in most regions of the country coming in significantly below old contracts?

So I just want to be careful that we're not overestimating where the average contract prices in 2020, given where current contracts are being signed.

Yes.

In our long-term forecast, we looked at the existing PPAs and the roll off of those and assume they would be converted to merchant pricing, and we didn't assume the extension of PPAs in that case.

The new PPAs, we looked at current market prices for PPAs and that was how we had forecasted it.

I don't know, Laura, do you want to add anything to that?

I know you're on the line so...

Yes, I agree with everything that you've said.

I think the market right now definitely is a much lower cost market, but would we go in for investment decisions and I think we've been very consistent on this.

We have a very disciplined approach to new investment and we're focused on our returns, not necessarily price.

And so I think it's all incorporated into our long-term plan, and we're doing the best that we can to compete in a very competitive market.

Appreciate that and obviously, I model to the returns too, but in terms of the modeling conventions you've given, I just wanted to be comfortable that sort of that the low end of that sort of range of average pricing expectations, sort of fully contemplated the fact that new contracts are coming in below old contracts, correct?

Yes.

And we -- keep in mind, we also have escalators in a number of the existing contracts too, so that helps through.

Got it.

Okay.

I just had gotten some questions on that recently, so I just wanted to make sure.

And our next question comes from Sophie Karp from Guggenheim.

I have a few, actually.

Maybe can drill down more on the Renewables and PPAs there.

What are you guys seeing in terms of trajectory of will you sign new PPAs as it relates to your maybe existing portfolio average?

And how is -- what's the dynamic in that market?

Is it getting more competitive?

Or is it staying stable?

Can you just give us more color on this?

Yes, I'll give you a quick answer and Laura can fill in.

But really, we're seeing -- it's been competitive all along.

I mean, we're competing with others pretty much on most of the projects.

Some of the ones where we -- with C&I customers, we do have relationships we build up so that goes a long way to helping us.

But it's competitive, and there's no doubt about it, and people are competitive on price.

In the past, people wanted renewable energy.

Now, it's renewable energy at a decent price.

So now, Laura, why don't you give your thoughts?

Yes, sure.

And it definitely is a very competitive market, and we would expect nothing less.

Jim is absolutely right, we have really worked to position ourselves and to create a competitive advantage in some of the services that we can provide in terms of customized solutions for customers.

So we've been very focused on those types of products and I think long term, that will pay off for us.

It is a complicated market and sometimes, these negotiations for PPAs take a lot longer than you would like them to, because they are long-term contracts and a lot of the customers that are entering the market now, their core competency and their core business is not energy.

And so there is an element of education that has to go along with the contracting process, which isn't something that we were working with in the past and you were just dealing with straight utility customers.

Got it.

And then did you guys have a chance to evaluate potential impact on your Renewables business from the tax reform proposals?

Yes, when we look at the tax reform, assuming there is a reduction in the tax rate from the 35% down to 20%, we would expect to see a pickup in our income.

It'll be roughly about a 4% pick up is what we'd look at on our growth, assuming nothing else happens.

Now if you add in the interest rate deduction elimination, if that occurs, that probably won't impact us too much mainly because most of our interest rate -- interest is at the utilities, the vast majority of it, and it would get passed through to the customers, along with the reduction in the tax rate.

And then if there's an immediate expensing of capital, that will have a bigger impact.

But right now, it would be probably be a plus for us when we look at our Renewables business by having a lowered tax rate and also keeping in mind that we have the PTCs and NOLs that we'd be utilizing, and those would be over a longer period of time then.

Great.

Okay.

And last one from me maybe could you elaborate on where you stand with the storm investigations in New York right now?

Bob, do you want...

Yes, Sophie, really no change at this point.

I think I had mentioned at the second quarter announcement that the investigation itself, the detailed interrogatory, some questions we received, we were essentially done with that and that's kind of where we are now.

So just waiting to see what, if anything, transpires from it from the commission and staff.

And now you still sort of taken the position that AMI is going to be behind that or that's now moving independently?

Yes, AMI, I would say, I don't think there's necessarily link, but AMI, where we are right now, we hope to reengage post EAM discussions, so end of the year time frame with the commissioning [go] by kind of midyear 2018.

And our next question comes from Angie Storozynski from Macquarie.

I have actually questions mostly about Renewables, but also how it ties into the Corporate interest expense.

So first of all, we're seeing some discounting of wind equipment by large wind OEMs, which is somewhat surprising given that the wind -- the newbuild market in the U.S. seems very robust.

So my question is, are you seeing it as well?

And do you know, for instances, the cost of newbuilds coming below your expectations?

And is it mostly being passed on to your customers, i.e., you can offer a lower PPA price?

So that's one.

Two is how should we think about the Corporate segment and the interest expense as we finance the growth in Renewables?

And even a bigger picture, it seems like leverage is being used more aggressively by some of the wind power developers to extract premium returns on the new wind installations.

And how do you guys think about what the appropriate leverage of these projects should be?

Yes, on the wind generators, we're seeing improvements in technology that we expect to continue.

So Laura, why don't you delve in on what we're seeing with the suppliers like the OEM right now?

Yes, definitely.

Each vintage of turbine that comes out is significantly improved in terms of performance.

And to your point, we are also seeing cost come down, which is absolutely critical, I think, for the industry in light of the current market and where we're seeing prices come in so much lower than they were a decade ago.

And so I am just speculating, but my sense is that the OEMs know that in order for us to compete and to be able to offer these products and to continue the growth, we do have to offer lower-priced PPAs.

And we can do that because of the improvements in technology and the reduced cost that we're seeing in the equipment.

Sure.

On the interest expense.

When we rolled out our long-term outlook, we had said we were going need at about $2 billion of incremental debt primarily at the holding company to fund all of our operations and cash needs, that's most likely where we can get the best lowest cost of capital is to do it there as opposed to at a project level.

And so while you may see some developers doing things at a project level, if you can get a lower cost of capital at the holding company, it would make sense to do that overall.

So by the end of 2020, we (inaudible) approximately $2 billion of incremental debt.

But is there any target, what that implies as far as leverage of the capacity being added?

I know that's not at the project level, but overall.

Yes, overall, it would take our current high 20% net debt to total cap up to mid-30s, 33%, 34%, 35% range over that period, but would still maintain strong metrics like net debt to adjusted EBITDA because we're growing EBITDA.

So we stay fairly constant over the period.

But having that capacity, as I mentioned earlier, then as these additional opportunities come along like offshore wind, additional transmission projects in Maine, we've got the capacity to fund those.

Recall neither of those opportunities are in our long-range plan right now, so we could fund those without overly stressing the balance sheet.

And our next question comes from Neil Kalton from Wells Fargo Securities.

Just a quick question on the RECs.

It looks like they've been nicely helpful this year.

I want to make sure I understand kind of what's going on year-over-year and how sustainable this kind of pricing might be going forward?

Well, the REC pricing is in the market, so it can move around quite a bit.

And it depends on the region you're also in because we see a lot of differentiation in the different regions.

So I think it's just one component of it, Neil, and I don't know have any -- RECs are one thing I'm having a hard time projecting.

So I don't know, Laura, can you do it any better?

I am right there with you and I don't think that we have disclosed any of our forecasts or anything, and I'm not even sure who at this point in time would have a good pulse on what those prices are going to be because we really have seen significant movement by region, just depending on supply and demand essentially.

So just a clarification.

Would it be fair to say that the $12 pricing that we've seen year-to-date is not what's in the base plan in terms of earnings going forward?

Would that be reasonable to say?

Yes, I think that's fair, Neil, because I think we were somewhat more like 5 to 7 because I think what we were looking at back then so -- and that's what we had in our plan.

It wasn't $12.

And we also have something like $26, $27 for energy prices too, I think, at the time for merchant.

And our next question comes from Chris Turnure from JPMorgan.

With the sale of 50% of El Cabo, should we now think about the long-term megawatt target for Renewables as 1,650?

And how are you kind of thinking about that in terms of the impact on both 2017 and longer-term EPS guidance?

In other words, is there a gain or anything that's been booked this quarter in relationship to that in addition to just the loss megawatt hours and sales from that?

Well, we had anticipated that we would -- that they would take the 50% or 49% of El Cabo all along and that was in our -- always in our plan.

And the 1,800 megawatts, assume the full amount because we'll be operating it.

So from that standpoint, it was 1,800, and the plan had always been that they would take the 50% and that was what we factored in.

Yes, so they'll actually take 49.5%, so we'll be able to consolidate it and account the full value -- or the full megawatts.

Got you.

So the 1,800-megawatt target is not a economic ownership interest target, it's a gross consolidated project level number.

Yes, because we'll consolidate it since we'll own over 50%.

Okay.

And then just in terms of the earnings impact, both for 2017 and longer term?

Yes, as I said, we had factored that in that they would -- of the partner taking their interest and the way we would finance it, we're looking at some tax equity for that, so that was always factored into our plan that way.

Okay.

And in terms of '17, specifically, there's no gains or anything in your adjusted or GAAP number from that signal or in this quarter or for the full year expectation?

No.

Nothing at all.

Okay.

And then if I look at kind of 2 things regarding year-to-date performance, I wanted to just get your input on those.

Corporate and other are basically your consolidated numbers minus Renewables and minus Networks implies that your earnings before tax is around $16 million for kind of the corporate and other, that the balance there, what is driving that considering there is some debt at the Corporate level there that I would think would have interest expense, and then also year-to-date, you guys have booked $12 million of income from equity investments and then you're booking a $10 million loss from investments at Renewables.

So I was wondering what's driving those?

Well, on the Corporate segment, there is also some intercompany interest income that disappears on consolidation when you look at the consolidated result.

But when you look at the standalone segments, as we fund construction at Renewables, there is an interest income stream until they go into service and then we basically advertise them.

And the second half of your question, income from equity investments, we have things like GenCon, the New York Transco.

I'm not sure -- you just mentioned a loss on equity investments.

I don't...

Yes.

Looking in the back of the slides, you have year-to-date performance by segments and there was $12 million of income consolidated for those, and then I think a $10 million loss at Renewables from equity investments.

Okay.

I'm not following that right away, so we'll take a look at and get back to you.

And our next question comes from Paul Patterson from Glenrock Associates.

Just a few quick ones.

So just in the wind capacity, that's solely due to the lack of wind, is that right, the decrease in wind capacity?

Well, the wind resource, the 5% is solely wind, yes.

Okay.

And then on the cost management, I guess, Greg Gordon's kind of question, I just want to sort of understand how, first of all, just on the initial restructuring charge, that suggests perhaps that there might be subsequent restructuring charges?

Is that right?

Or how should we think about that?

Yes, we're looking at voluntary retirement plan for employees -- some employees, and we have an initial amount that we booked, and I would expect we'll have something more in the fourth quarter.

Okay.

And is the -- are the restructuring charges, are they part of the ROE calculation at Networks?

No.

They're not?

No, they're separate.

It never get included in rates.

So in other words, if you -- in other words, the restructuring charges and the negative impact on GAAP earnings, that is not part of the calculation for determining whether or not you're in the excess earnings rates, is that right?

That's correct.

It is not included, yes.

Okay.

And then just, in general, since you guys did so well on best practices and stuff, do you see that as sort of a run rate?

Or is there anything that was sort of deferred in terms of expenses or costs in the third quarter?

Well, this is an ongoing program that's going all the way through to 2020.

So we would expect that we're going to have opportunities going all the way through in the next few years, and it's not just a one-shot deal.

So we are working on a number of projects that are kind of -- take a little time to implement.

So that's why we're -- I would expect it's going to be an ongoing process.

It won't end in 2020 either.

I mean, we're going to have an ongoing focus on cost management and best practices.

So don't assume that it's just going to end in the third quarter or the fourth quarter.

Well, I didn't mean that your initiative would end in that.

What I meant was, was there any cost that we should think of as being sort of, perhaps, temporary in terms of, let's say, a deferral of cost or you didn't do something that you might have done because just from a sort of a cost management, (inaudible) do you see sort of what I'm saying?

Yes, I don't think there's a lot in the way of deferrals.

I think we were just eliminating what I would characterize as the things that we don't need to do, right, just eliminating unwarranted expenses.

We're trying to minimize and get as efficient as we can.

Okay, great.

And then just finally on the October 5 filing at FERC and just sort of your thoughts, in general, considering what FERC's sort of ruling has been regarding (inaudible), I mean, just sort of their comments and their order in terms of they don't see sort of buying into sort of the transmission owners' arguments regarding what this -- what (inaudible) necessarily means with respect to ROE and what have you.

Would you like to comment a little bit on that?

I mean, I know you guys filed on October 5. I think, if I'm not wrong, the order came out the day after.

And I'm just wondering how we should sort of think about that in light of their rejection of the compliance filing?

Yes.

I mean, that the -- what we filed essentially said, it should all get thrown out because, essentially, the remand from the courts, you could argue that's the reason that they sent that back to FERC, that, that same rationale would apply to all the other complaints.

So that's really what we're saying there.

And I think, in reading what FERC came back with on the first complaint and our request to basically adjust tariffs 60 days post a quorum, they really, in my mind, didn't get to the merits of the ROE.

It was more they were concerned around, if you would, whiplash of ROEs back and forth if we move the rate back to the 11.14% from 10.57% and they ruled 2 months later on another number.

So they essentially said, no, let's wait until we make a decision with regards to what the court came up with in the first complaint.

And our next question comes from Joe Zhou from Avon Capital Advisors.

It's Andy and Joe.

Just a couple of clarification questions just on the wind.

Can you give us any idea what current PPAs are being signed at depending on the region, I guess?

We haven't been -- we won't disclose prices on any particular PPAs.

Andy, I mean, if you look in different areas, you get into Texas and the Mid-Continent, those are in the -- probably in the mid-20s, that's the market today for those.

And New England, it's going to be higher and Northwest a little higher.

But we're not going to, obviously, comment on any particular PPA, so.

And how should we just think about it margin-wise relative to existing PPAs you have?

Are the margins the same?

Obviously, prices are lower, but equipment, as you talked about, is lower, but how about the margin that you're earning on that?

We look at the minimum, like a 200 basis points over our WACC for an internal rate of return and that's really how we evaluate it and evaluate the projects.

So we target to earn that as a minimum.

Yes, we're looking at internal rate of return on a project as opposed to income accretion or anything else.

Okay.

And what IRR should we be using?

We don't give away the WACC.

I mean, that's one of those -- it's a competitive advantage, Andy.

Okay.

And then a couple of other questions.

On the $2 billion of debt that you were talking about by I think it was 2020, where will that sit at the parent?

Or is that project debt?

It is the parent.

If you look at it, we pretty much fund our CapEx from our cash flow more or less and then within 96%, and so really the dividend is what you can look at it that way is what we're raising debt for.

So that's where the $2 billion will come from.

It will be at the parent more than...

And so just to circle back on the tax reform that in the 4%, does that include this $2 billion of debt if there was a lower tax rate, everything else equal?

Yes.

Yes, we're looking at through 2020.

Right.

So the 4% -- the $2 billion is based -- or your 4% is based on a 20% tax rate both on the deductibility of the $2 billion of debt or other parent debt, and then that's the minus and then the plus would be, obviously, the lower tax rate at the Renewables business.

And here, just to understand the Renewables business, how -- with the lower tax rate, wouldn't, again, depends on the company, but I guess, you would only benefit on the wind projects or solar projects that make money without the PTCs, is that correct with the merchant and things like that?

Or...

No.

Just trying to figure out how we came up with that number, make sure we just take the tax rate and lowering it by 15%?

Or is it only on a kind of a portion of the assets?

Well, the Renewables' effective tax rate is lower today because of the PTCs, as you say.

But that's going to get paid back over time and so it expends that time out, but we'll have debt at the holding company so we'll lose that interest deduction.

And when we look at it on a consolidated basis, net-net, the lower rate is going to benefit on a consolidated basis that if we go to 20% tax rate, lose the interest rate deduction, overall that's a plus of about 4%, which is not as big as you might expect given a reduction from 35% to 20% mainly because Renewables has a low tax rate today.

Okay.

So just to make sure I understand, I guess, we can talk about this offline too but or down at the EEI, but the lower tax rate benefits the consolidated, it's not the Renewables and obviously not the utilities, but there's something going on, on the consolidated basis that allows you to...

Yes, we file a consolidated tax return, right.

Yes.

Right, right, right.

I understand.

And then just on the tax benefit you have for the year, what is that from that allowed Corporate to do a little better?

The total consolidated effective tax rates coming in little better than expected as we've trued up various unitary tax filings, get a more current assessment of the impact of PTCs, et cetera.

It's just where we are now versus where we thought we would be back in February.

We're doing a little better there.

And at this time, I'm showing that we are at the scheduled hour mark.

And I'd like to turn the call back to the company for any closing remarks.

Well, I want to thank everybody for participating.

And if you have further questions, please contact our IR department, and thank you all again.

And we'll see most of you at or all of you at EEI.

Ladies and gentlemen, thank you for your participation in today's conference.

This does conclude the program.

You may now disconnect.

Everyone, have a great day.