Patricia Cosgel - IR Jim Torgerson - CEO Rich Nicholas - CFO Bob Kump - CEO, Avangrid Networks, Inc. Laura Beane - CEO, Avangrid Renewables, LLC

Julien Dumoulin-Smith - Bank of America Merrill Lynch Greg Gordon - Evercore ISI Sophie Karp - Guggenheim Securities Angie Storozynski - Macquarie Research Neil Kalton - Wells Fargo Securities Christopher Turnure - JP Morgan Paul Patterson - Glenrock Associates Joe Zhou - Avon Capital Advisors

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. You may begin ma'am.

Thank you, Terence 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 Torgerson, 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're 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 US 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 this conference call, in the Risk Factors section of the accompanying presentations 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 presentations also include references to non-GAAP financial measures. You should refer to the information contained in the slides accompanying today's presentation for definitional informational and reconciliations of non-GAAP financial measures to the closest GAAP financial measures. With that said, I will turn the call over to Jim Torgerson.

Thanks Patricia. And I want to welcome everybody to our third quarter call. With us today besides Rich and Patricia and the entire team, we have Bob Kump, who's the CEO of our Networks Business and Laura Beane, who's 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 in our long-term plan. Now a look at the financials, first off for the third quarter we had net income of $99 million or $0.32 a share which from an SEC reporting basis was down 9% from the third quarter 2016 and we had nine months results of $458 million or $0.48 which was up 8%. On an adjusted basis and the adjustments are really related to taking out the gas storage business mark-to-market and earnings and losses, restructuring charges which the initial ones we had and then again from some 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 nine months we were $494 million or $0.60 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% or $1.6 billion for the nine months ended in September; much of that increase is in our Renewable business, but also a good portion of Networks as well. We're executing on our adding PPA. So far this year we've added 487 megawatts of new win PPAs. Which includes 86 megawatts which were signed in the third quarter and we continue to add our renewable pipeline, we'll talk about that in a minute, but we're now off to an 8 gigawatt pipeline which is an increase of 0.9 gigawatts it's just in the last quarter. We filed a rate settlement with Southern Connecticut Gas with the consumer counsel [technical difficulty] 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, early December. It had 9.25% ROE and 52% equity. Now one of the things I'm particularly proud of, is we - we actually have a very extensive suit of policies and procedures. They're formed a basis for our governance, for our ethical and compliance programs and also we have the best practices. We've gathered from US and from internationally. In 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 Board Room 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 nine months. Now net income and earnings per share reflect the inclusion of gas storage all things I said that weren't included in the adjusted numbers. They also reflect a small restructuring charge, initial restructuring charge 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% and a quarter both in earnings and earnings per share as we and then 14% for the year-to-date. As part of the reason for the adjustments were excluded the gas storage business. We're continuing to evaluate that business and expect to finalize the 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, what we would consider normal, but 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 added another 208 megawatts from our Desert Wind project which probably added a $0.01 in itself. So really the 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 nine months, we were almost $1.6 billion, almost evenly split. A little more, about $100 million more in networks than renewables and as I said renewables had a number of projects going on and you can see that on the next page on Page 9. We have five projects that will be completed in 2017, it will add 590 megawatts, 56 megawatts of solar and 534 megawatts of wind. The Gala Solar project with 56 megawatts and being sold to large C&I customer. Is right now test energy being implemented along with El Cabo, the 298 megawatts. Those are in commissioning where we're generating some test energy and then 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 5,900 of it is running full day-to-day, the balance maybe in the 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 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 and the pipeline projects we've added 600 megawatts of wind and 300 megawatts of solar and all this is spread out across the country in Wyoming, Oregon, Michigan, Illinois, New York, Maryland and Connecticut. It does not include any of our offshore wind in that pipeline. And all of 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 COD in 2019, then we have a Texas Wind project which we signed with Austin Energy for 200 megawatts and the latest one, new PPA with a major footwear and apparel company of 86 megawatts also in Texas which will COD late in 2019 as well. So we're looking at a long-term plan, we now have secured of the 1,800 megawatts in our plan 60% of 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 in 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. Are going to 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 rates but we've been deferring the recognition of it, until it actually goes live and it's used in useful. We also completed earlier this year Ginna Retirement and the [indiscernible] transmission project which were about 250 million of transmission project. 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 Rail Road Corridor that's a $175 million project it 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 two areas we're going to spend about $570 million on replacing bare steel and cast iron within some expansion and we also, an LNG enhancement in Connecticut on two different LNG sites. We have the low [indiscernible] which will be operational next year in 2018, which is another $70 million. So you look at our high likely capital expenditure 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 AMI. But without those two we have 91% of capital expenditures, are secured for networks business and 9% are considered highly likely which we feel pretty strongly will happen in starting 2018. Now turning to Page 12, we have in New York we're working on a collaborative earnings adjusting mechanism and working with the staff on negotiations and those are ongoing. We expect that to be implemented in 2018 and that provides incentives that would actually increase the ROE, if the targets are achieved. The determination of AMI as I mentioned was deferred till late 2018 so we expect a decision in the first half of 2018. In Southern Connecticut Gas and we have a three-year rate settlement with the OCC and the PURA Prosecutorial Unit that was filed with PURA on October 16 and it was amended slight for some minor changes. I think they totaled maybe $100,000. But the accumulative revenue increase is going to be about $11 million, importantly the ROE is 9.25% and 52% equity. Rate base is going from $544 million to $618 million by December 2020. And the capital plan does include the Distribution Integrity Management Program which allows us to recover 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 in the cost recoveries actually the same, they're very similar what we have for Connecticut Natural Gas. It also add relative decoupling which is required by legislation. So and also in the last week, Connecticut PURA opened a docket to review Gas LDCs' their gas 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 two companies Avangrid and [indiscernible] 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 24x7, 365 days out of the year and we're 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 employees that require all employees to follow all the rules and laws of 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 and 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 needed, even on the coldest days. So that's the objective we have. At FERC at the Quorum has been restored as I think all of you know, with the Senate confirming Rob Powelson and Neil Chatterjee and Rich Glick and Rob [ph] McIntyre as supposed Chair are still waiting for the full Senate to approve it. In the ROE Complaint Number I, FERC rejected the New England TOs filing to being 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 for the FERC trial staff filed testament to ALJ decision is expected in March and on October 5, the New England TOs filed for FERC to dismiss XE all [indiscernible] the ROE complaint is not being in compliant with Section 206 requirements as was determined by the DC Court of Appeals. So turning to Page 13, we're 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 problem, we were able to mitigate much of that and we will continue working on that. It just shows that 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 2017 guidance adjusted earning for share outlook of $2.10 and $2.35 and we're executing on opportunities in our core business, we had new and existing wind projects. Our 2017 investments are really in line with expectations and our three-year rate plans in Connecticut and New York are giving [indiscernible] 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 renewable and a lot of the transmission project 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's that will be in Massachusetts. So we feel very good about the future and there are opportunities to take advantage of those things that are becoming along through the pipeline in the not too distant future. So with that, I'm going to turn it over to Rich Nicholas who's going to present our financial results in a little bit more detail.

Thank you, Jim. 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 nine-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 multi-year rate plans at some of our networks companies as well as new capacity in the renewable business. However as mentioned the wind resource has been below average, well 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. Then I'll review the business segment results on the following slides. So turning to Slide 17, to look at the nine 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 for moving what was the UIL holdco debt up to corporate. In addition the first nine months include $5.2 million after tax charge for sharing in New York which represented the portion of our earnings share with customers for the first rate year because we were able to earn above the allowed return in that period. For the renewable segment, the nine months adjusted net income increased $11 million versus 2016. Then the new capacity in 2017 resulted in a slightly higher wind resource for the period of, although still below normal for the first nine 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 nine months was approximately 31% on a management reporting basis, but which includes production tax credits in 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 a non-core business gas storage net income for the nine 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 of segment results. here you can see network 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 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 renewals business and we've got graph later on Slide 21, will have 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 multi-year forward looking rate plans, revenue decoupling and various tracking mechanisms and for UI and certain main power, our transmission rates we utilized deferred formula rate process, which provides our annual [indiscernible]. The New York rate plans continues for May, 2019 the United Illuminating plan goes through December, 2019. Now the proposed settlement, we have Southern Connecticut Gas will be effective through December 2020, if approved. Now we're currently evaluating the need for the next rate filings for Connecticut Natural Gas, Berkshire Gas and Central Main Power. And we're fully committed to continuing our forward 2020 program to implement those practices. Looking now at Slide 20 for the renewable business. The primary driver is there is nine 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 nine months compared to last year. The low factor decreased 3% as new capacity that's not fully online for the full period of just in test mode impacts that calculation. We did see our average PTA prices decline 3% offset somewhat by increases in REC pricing. In all in, our pricing is down just 3%, the average PTA of $55.80 is consistent with our long-term outlook of $56 as we had plan for certain PTAs to roll off while others have escalator in the low level 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 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 in under constructions in networks and renewable. Our cash CapEx year-to-date has grown to $1.7 billion. We continue to have solid cash flows from operations that would fund our growth of about $1.3 billion [indiscernible] this for the nine months in 2017 and the different between cash and operations of CapEx is being supported by short-term credit facilities for now. Moving to Slide 23, looking at our credit profile our net debt is now $6 billion, now we have very stable credit ratings BBB plus, Baa1 with strong metrics of 2.9 times 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 sub segments, networks guidance is actually being increased by $0.02 on both the lower and upper ends of the range due to the implementation of best practices, while renewable 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 normal wind in the fourth quarter and that we complete the projects on time as expected. So with that, I just look forward seeing many of you at the EEI Financial Conference in a couple of weeks and now I'll hand the call back to our operator Terence for questions.

[Operator Instructions] and our first question comes from Julien Dumoulin-Smith from Bank of America Merrill Lynch. Your line is open. Julien Dumoulin-Smith: Just a couple networks focused questions, if you can. First on New York I'd love to hear how to the earnings adjusted mechanism discussions are ongoing. I know in the last call, you specifically called it out on negotiations where do 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, what is that saying and how you're thinking about project over there?

Yes, let me deal with the ROE. We've been booking at 10.57 and we'll continue doing that which is what FERC has determined. So that will stick with then, until FERC tells us something different and Bob you may want to address the other part.

Sure. Good morning, Julien. As related to the earnings adjustment mechanism, we've 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 the DER on our system. The area that we're still working on is the value of those incentives. You'll recall that in the TCIP [ph] 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 piece that we're still negotiating in terms of 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 2018, 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 what I'll say at this point is lesson 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 it and moving forward. Julien Dumoulin-Smith: Got it, excellent and then just to be clear on the EAM stuff, just coming back to New York. This would be for a 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 of the things I forget to mention on the Western Europe just to remember that was not in our numbers, so still disappointing nonetheless. Julien Dumoulin-Smith: Right, clearly. Thank you very much.

And our next question comes from Greg Gordon from Evercore. Your line is open.

Couple questions. First when we think about your cost optimization initiatives that you've really started to just rollout, are we looking at I mean I think about three business segments, the corporate parent, the utilities businesses and EBIT IBERDROLA and Avangrid Renewables. Are you expecting to see demonstrable improvement in costs in all three businesses? So when we think about earnings drivers at the utilities, do you still see opportunity to see improvements in ROE given the sharing arrangements or earned ROEs you have and what's your restrictions first, 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 benefit. So when I think about modeling over the next three 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 as networks will have it and again we said all along we want to be able to get into the sharing ranges and that's one of the mechanisms we're used to do that. I also see at a corporate we'll be looking at the 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 keeping in mind that the corporate gets allocated back to networks and the renewables, so it will pull through that way. But everything it's across - networks is 70% of the business, 70%, 75%, so that's probably where the bulk will be but networks corporate and then probably renewable 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 are also looking at how do we do it as efficiently as possible, so everyone is involved in the forward 2020 program.

Great, my second question is I know you're adding substantial amount wind capacity, hopefully you do beat your modest target for 2020 and we know that you've given and assumed decline and weighted average PPA price over the period, does it that fully bakes in the expectation? Does that fully bake in the expectation sort of algebraically? The fact that new contracts are obviously most recently the country coming in significantly below old contracts. 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've 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, good morning. Thank you. 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. So I think it's all incorporated into our long-term and we're doing the best 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 sort of the low end of that, range of average pricing expectations sort of fully contemplated the fact that new contracts are coming in below old contracts.

[Indiscernible] the escalators and the number of the existing contracts too, so if that helps.

Got it. Okay I have gotten some questions on that recently, so I just wanted to make sure. Thank you

And our next question comes from the Sophie Karp from Guggenheim. Your line is open.

I have a few actually, so maybe can you drill down more in the renewable and PPAs there. What are they seeing in terms of trajectory from where you're signing new PPAs as it relates to you're the existing portfolio average and how is - what's the dynamic in that market? Is it getting more competitive or is it staying less stable? Can you just give us more color on this?

Yes I'll give you a quick answer and then Laura can fill in. but really we're seeing - it's been competitive a lot. 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 them your thoughts.

Yes, sure. And it's definitely is a very competitive market and we would expect nothing less. Jim is absolutely right, we've 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 too because they're long-term contracts and a lot of the customers that are entering 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 we were just dealing straight utility customers.

Got it. And then did you guys have a chance to evaluate potential impact in your renewable business from the tax reform proposals?

Yes, when we looked 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 will be roughly about 4% pick up is that we've looked at on our growth. Assuming nothing else happens. Now if you add in the interest rate deduction elimination that occurs that probably won't impact us too much mainly because most of our interest is at the utility the vast majority of it and it would get pass through to customers along with the reduction in the tax rate. And then, if there is an immediate expensing of capital that will have bigger impact, but right now it would be a probably be a plus for us when we look at our renewal business by having to lower tax rate and also keeping in mind that we have the PTCs and NOLs that would be utilizing and those would be over a longer period of time then.

Great. Thank you. And last one from me. Maybe could you elaborate on where you stand with the storm investigations in New York, right now?

Yes Bob will.

Yes, Sophie really no change at this point. I think I had mentioned at the second quarter announcement that the investigation itself, a detailed interrogatory questions we received, we were essentially done with that and it's where we are now, so just waiting to see what if anything transpires from it, from the commission and staff.

And [indiscernible] taken the position at the AMI is going to be behind that or that's now moving independently.

AMI I would say I don't think they're necessarily linked, but AMI where we are right now, we hope to reengage post EIM discussion, so end of the year timeframe with a commission will by to mid-year 2018.

Got it. All right. I'll jump back in the queue.

And our next question comes from Angie Storozynski from Macquarie. Your line is open.

So I've actually questions mostly about renewables but also have a 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 new build market in the US seems a very robust. So my question is are you seeing at a swell and do you know for instance as the cost of new build coming below your expectation and is it mostly being passed onto 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 and renewable 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 in what the appropriate leverage of these projects should be? Thank you.

Yes on the wind generators we're seeing improvements in technology that we expect to continue, so Laura why don't you delve into, what we're seeing with the suppliers at 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're 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 price is becoming so much lower than they were a decade ago. And so I'm just speculating but my sense is, that the OEM's know that in order for us to compete as we're able to offer these products and to continue the growth, well you do have to offer lowered price 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 to need to add 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 oppose to add a project and so while you may see some developers doing things at a project level, if we can get a lower cost to capital with the holding company it would make sense to do that overall. So by the end of 2020, we're approximately $2 billion of incremental.

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. Would still maintain strong metrics like net debt to adjusted EBITDA because we're growing EBITDA so we stayed fairly constant over the period. But having that capacity as I mentioned earlier then is 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 in the our long range plan right now, so we could fund those without overly stressing the balance sheet.

Okay, thank you.

And our next question comes from Neil Kalton from Wells Fargo Securities. Your line is open.

Just a quick question on the RECs, looks like they've been nicely helpful this year. And 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 in the market, so it's - 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. I don't 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'm right there with you. I don't think that we've disclosed any of our forecasts or anything and I'm not even sure who at this point in time would have a good polls 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. Will 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 or like $5 to $7 because I think what we were looking at back then so and that's what we heading in our plan, it wasn't $12 book.

All right thank you.

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

Right, thanks.

And our next question comes from Chris Turnure from JP Morgan. Your line is open.

With the sale of 50% of El Cabo, should we now think about the long-term megawatts 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 they would take the 50% or 49% of El Cabo all along that was always in our plan and the 1,800 megawatts assumes the full amount because we'll be operating it. So from that standpoint it was 1,800 and the plan had always been they would take the 50% and that was what we factored in.

So they'll actually take 49.5%, so we'll be able to consolidate it and count the full megawatts.

Got you, so the 1,800 megawatt target is not an economic ownership interest target, it's a gross consolidated project level?

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've factored that in, they would - off the partner taking their interest and the way we would finance it, we're looking at some tax, at tax equity for that. So that was always factored into our plan that way.

Okay. And then in terms of '17 specifically there's no gains or anything in your adjusted or GAAP number from a single [ph] for this quarter or for the full year expectation?

No nothing at all.

Okay. And then if I look at kind of two things regarding year-to-date performance, I wanted to just get your input on those. Corporate and other or 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, 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 your booking a $10 million loss from investments at renewables. So I was wondering what's driving those?

So on the corporate segment there's also some inter-company interest income that disappears on consolidation when you look at the consolidated result, but when you look at the standalone segment as we fund construction at renewables there's an interest income stream until they go into service and then we basically equitize [ph] 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 mentioned a loss on equity investments, so I don't.

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

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

Okay, thanks.

And our next question comes from Paul Patterson from Glenrock Associates. Your line is open.

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 is 5% is solely wind, yes.

Okay. And then on the cost management, and I guess, Greg Gordon's kind of question, I just want to understand how first of all, just on the initial restructuring charge, that suggest 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 some employees and we have an initial amount that we book then we're - I would expect we'll have something more in the fourth quarter.

Okay. And are the restructuring charges, are they part of the ROE calculation at Networks?

No.

They're not.

No they're separate. Ever get included in rates.

So 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 sort of a run rate or is there something 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 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're working on a number of projects that are kind of it will take a little time to implement, so that's why we are - I would expect it's going to be an ongoing process and 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 there any cost that we should think as being sort of perhaps temporary in the deferral of cost or you didn't do something that you might have done because just from a sort of a cost management, do you see sort of what I'm saying?

Yes. I don't think there is a lot in a way of deferrals I think we were just eliminating what I would characterize is as things that we don't need to do right. Just eliminating unwarranted expenses and 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 sort of ruling has been regarding in their vein, I mean, just sort of their comments and their order in terms of they don't see buying into sort of the transmission owners arguments regarding what does - what a [indiscernible] mean - 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 and 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 filed?

Yes, what we filed essentially said it should all get drawn out because essentially the remand from the court you could argue that the reason that they extend that back to FERC that same rationale would apply to all the other complaints, so that's really what we're seeing there. And I think in reading what FERC came back with the first complaint and our request to basically adjust tariff 60 days post quorum, they really in my mind didn't get to the merit of the ROE, it was more they were concerned around it you would whiplash of ROE back and forth, if we move the rate back to the 11/14 and 10.57% and they ruled two months later on noted [ph] number. And so they essentially said now let's wait until we make a decision with regards to what the court came up with in the first complaint.

Okay, thanks a lot guys.

And our next question comes from Joe Zhou from Avon Capital Advisors. Your line is open.

It's Andy and Joe. How are you guys doing?

Very good.

Everything is going well for you. I'm glad to see that. Just a couple 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 to - we won't disclose prices on any particular PPAs. Andy I mean if you look in different areas, you get into Texas and the midcontinent those are in the probably 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 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 [indiscernible] as you talked about is lower, but how about margin that you're earning on that.

We look at minimum and like 200 basis points overall WAC for an internal rate of return and that's really how we evaluate it and evaluate the project. So we target to earn that as a minimum and so we don't [technical difficulty]. We're looking at internal rate of return on the project as oppose it income accretion or anything else.

Okay and what IRR should we be using?

We don't give away the WAC. I mean that's one of those - too competitive advantage Andy, as [indiscernible] predict.

Okay and then couple other questions. On the $2 billion 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's the parent. If you look at it, we pretty much fund our CapEx from our cash flow more or less and then within I think 96% and so really the dividend is what you can look at it that way, is what we're raising debt or so that's where the $2 billion will come from, it will be at the parent.

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

Yes.

Okay.

We look at till 2020.

All right so, the four is for $2 billion is based or your 4% is based on 20% tax rate both on the deductibility of the $2 billion of debt or your other current debt and then that's the minus and then the plus would be obviously the lower tax rate at the renewables business. And can I just understand the renewables business? How would 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 or things like that or? Just trying to figure out how we come up with that number. I mean, should we just take the tax rate and lowering it by 15% or is it only on kind of portion of the assets?

The renewables effective tax rate is low today because of the PTCs as you say, but that's going to get paid back overtime so it expends that time out, what 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 losing interest 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 rates benefits the consolidated, it's not the renewables, obviously not the utility but [indiscernible] going out on a consolidated basis that allows you to.

Yes, we [indiscernible] consolidated tax return.

Right, I understand and then just on the tax benefit you have for the year, what is that sum? That allowed corporate to do a little better.

The total consolidated tax rates coming in a little better than expected as we've chewed up unitary tax filings, get the more current assessment of the impact of PTCs etc, it's just where we are now versus where we thought we would back in February, we're doing a little better there.

Okay, should we cap [technical difficulty].

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