Good morning, ladies and gentlemen and welcome to the AVANGRID Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] I would now like to turn the conference over to your host Ms. Patricia Cosgel, Vice President of Investor Relations. Please go ahead ma'am.

Thank you, Jason, and good morning to everyone. Thank you for joining us to discuss AVANGRID's Third Quarter 2019 Earnings Results. Presenting on the call today are Jim Torgerson, our Chief Executive Officer; and Doug Stuver, our Chief Financial Officer. A team of AVANGRID officers will also be participating in 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 this 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. I will now turn the call over to Jim Torgerson

Thanks, Patricia, and good morning, everyone and thank you for joining the call. I'm going to start on page 5 with the financial results in the third quarter, which reflect really a positive performance for Renewables had improved production due to better wind resource and new assets and service during the quarter. So for the third quarter of 2019 net income was $150 million or $0.48 a share, up about 20% year-over-year. Year-to-date net income was $477 million or $1.54 a share which was in line with last year. Our adjusted net income in the third quarter was a $123 million, or $0.40 a share which was down 11% versus 2018. And year-to-date adjusted net income amounted to $442 million or $1.43 a share, which was down 13%. We continue to really make good progress executing on our strategic plan. In Networks settlement negotiations for NYSEG and RG&E rate cases began on October 22 and the Maine rate case is in progress. This New York staff and the Maine bench analysis included enhanced recovery mechanisms for outage restoration and staging cost and with these in place we would have been able to recover about 90% of the staging and outage restoration costs experienced in 2019. Moving on our New England Clean Energy Connect transmission project is really on track to start construction in the second quarter of 2020. Concerning our renewable projects, we have executed over 2,000 megawatts in power purchase agreements exceeding our long-term outlook target. We commissioned 427 megawatts year-to-date and we have approximately 562 megawatts of onshore wind under construction. During the third quarter, we executed new PPA with Portland General Electric for the repowering of our 75-megawatt onshore wind project Klondike II in Oregon. In addition we're optimizing our Renewable pipeline through the agreement with Axium to sell a 50% ownership interest in a wind farm in a solar project for $112 million which is expected to close in the fourth quarter. Both projects are located in Arizona and have long-term PPAs and this is going to be a continuing strategy to recycle capital and optimize our pipeline projects and our assets. For our Vineyard Wind offshore project BOEM is expected to issue a Supplemental Environment Impact Statement by late 2019 early 2020. And during the third quarter Vineyard Wind submitted separate bids in the Massachusetts and Connecticut offshore wind RFPs and the winning bids they're expected to be announced in November. In addition on our Forward 2020+ plan we are on track to achieve savings in the range of $70 million to $85 million pre-tax in 2019 it's about $45 million pre-tax savings achieved in the first nine months. This is helping to mitigate the impacts of our higher outage restoration and staging costs particularly in New York. As part of our continued organizational transformation designed to improve communications and to enable better strategic coordination and more efficient decision-making we are developing an East Coast presence for the Renewables business. The change means we will be relocating some senior leadership roles to Connecticut, specifically origination development investment and business performance. We also announced some changes to leadership that are designed to help us in the growth of Renewables notably Laura Beane has decided that she'll be leaving the organization. Now, we have the greatest respect for Laura and we really do wish her well and thank her for all the contributions she's made to AVANGRID. Alejandro De Hoz, who has been leading the U.S. offshore business for the last two years has been appointed as President and CEO of AVANGRID Renewables. Now Laura is going to staying through the end of March to assist us with this transition. And really this is a very exciting time for AVANGRID Renewables and I'm optimistic for the growth prospects of the business and the ability of our team to deliver on it. Moving to Slide 6. Note that the GAAP earnings per share were impacted in the quarter by several factors noted on this slide, which are excluded from the adjusted earnings per share most notably there was a large mark-to-market impact in the third quarter that positively impacted earnings per share. For the quarter, adjusted earnings per share were lower compared to the third quarter of '18, primarily driven by increased outage restoration staging costs, including the non-deferrable minor storm expenses in Networks. And then interest expense in Corporate which was offset by positive performance in Renewables. For the nine months GAAP earnings per share remained flat at $1.54 versus last year adjusted earnings per share decreased about 13% to $1.43. The key drivers for the nine months adjusted results by business are for Networks results reflect the impact of higher depreciation and higher staging outage restoration cost these negative impacts more than offset the rate increases in New York, Connecticut and Massachusetts. For Renewables adjusted earnings per share decreased primarily driven by lower prices expiring PTCs, lower wind resources for existing assets and this was partially offset by a contribution of new capacity, higher revenues from Klamath and higher minority interest income. For Corporate adjusted earnings per share decreased by $0.05 to $0.09 a share driven by a higher interest expense. The Forward 2020+ mid-period assessment savings helped to mitigate the impacts from a higher outage restoration staging costs particularly in NYSEG and lower wind production primarily in the first quarter. The mid-period assessment provided about $0.11 savings versus our expectations. Now today, we are revising upward our 2019 consolidated U.S. GAAP earnings outlook to $2.36 to $2.46 per share from the previous estimate of $2.18 to $2.28 per share, really due to changes in mark-to-market expectations and we're affirming our 2019 consolidated adjustment earnings guidance outlook of $2.25 to $2.35 per share. Moving on to the highlights from our Networks business on Slide 7. In New York, NYSEG and RG&E filed one-year rate cases in May requesting new rates. We are requesting a 9.5% ROE on a 50% equity ratio and proposing additional capital for our resiliency plan, which includes an increase in vegetation management the program to a five-year cycle at NYSEG and also for AMI. Now the staff proposed an ROE of 8.2% and equity of 48%. They agreed with 100% of company proposal for AMI and 2019 resiliency plan and recommended an increase for vegetation management from $30 million to $57 million per year. The company filed it's rebuttal on October 15 and settlement negotiations began on October 22. The effective date of new rates assuming an approximately 11 months suspension period will be April 17, 2020. Now the rate cases are expected to substantially mitigate the impacts of outage restoration staging costs and over time. The reduced outages and future costs will be positively impacted by investment to replace aging infrastructure, treatment of staging costs, tree trimming and increased vegetation management for NYSEG increased internal linemen hires and apprentice programs to support the future retirements with the qualified resources. As I said, we would be able to recover or defer about 90% of the outage cost experienced in 2019 through the regulatory mechanisms that would be implemented in New York and Maine. On Slide 8, in Maine CMP has ongoing rate case, but the decision is expected in early first quarter of 2020. That was originally targeted for October of 2019. So, in October of 2018, CMP filed a rate case requesting an ROE of 10% which is above the current 9.45% and an equity ratio of 55% which is above the current 50%. We have proposed increasing Tier one and these are normal storms or minor storms we'll call it of a rate allowance to $8.1 million from the $4 million annually. Staff proposed an ROE of 8.75%, an equity of 50% and staff is recommending lowering the ROE by 75 to 100 basis points due to customer billing and customer service issues. The company response recommended organizational changes and the establishment of a $6 million customer benefit fund, plus the establishment of an energy assessment pilot with Efficiency Maine. In August, the Maine PUC decided to link the CMP rate case with the completion of the metering and billing docket. For the CMP metering and billing docket, hearings will begin on November five and a decision expected by December 20. Now on Slide 9 concerning our $950 million New England Clean Energy Connect transmission project that will deliver 1200 megawatts of Canadian hydropower in the New England grid. We expect to start constructing the second quarter of 2020. The project is progressing well. In September, CMP filed a request to reroute the project using the Merrill Strip Alternative to avoid the Beattie Pond protected area and the Maine Land Use Planning Commission reopened the docket for the limited purpose of reviewing this alternative route. In early October, the Maine Land Use Planning Commission and Department of Environmental Protection issued joint procedural order determining that no additional hearings were necessary. Based on this, the Maine Land Use Planning Commission deliberation vote and the DEP decision are expected in the first quarter of 2020. U.S. Army Corps of Engineers approval is expected in the second quarter about 60 to 90 days after the Maine DEP decision and then ISO-New England I.3.9 approval is expected in the first quarter of 2020. The Presidential Permit which is not needed to start construction it's just needed across the border is expected to be should approximately 60 days after the Army Corps of Engineers and the ISO-New England approvals. We are holding to our timeline to start construction in the second quarter of 2020 and expect completion by the end of 2022. For renewables, on Slide 10, we are exceeding by 223 megawatts, our 2020 target to add 2,000 megawatts of executing wind and solar contracts. Of these 2,223 megawatts, 427 megawatts of onshore wind projects came online so far in 2019 including our Patriot Wind 226-megawatt wind farm in Texas that was purchased at the end of June and the Montague 201-megawatt wind farm in Oregon that came online this month. And so we have 562 megawatts under construction and we have 1,234 megawatts of contracts signed that are expected to come online between 2020 and 2022. We've increased our pipeline to 16.5 gigawatts from 15.9 gigawatts in the second quarter. This breaks down to 5.7 gigawatts of onshore wind, five gigawatts of offshore wind, and 5.8 gigawatts of solar. Our repowering plan is also on track. During the third quarter, we executed a new PPA with Portland General Electric for the repowering of our 75 megawatt onshore wind project of Klondike II in Oregon to be completed in 2020. We with this addition we are already exceeding our 2022 repowering target. In addition, we are optimizing our renewal pipeline through the agreement with Axium Infrastructure to sell a 50% ownership interest in the 65 megawatt Dry Lake II wind farm and 20 megawatt Copper Crossing solar project both located in Arizona. This is really a continuation of our ongoing strategic initiative to monetize our pipeline. We expect to close the transaction in the fourth quarter this year for a $112 million sale proceeds. The earnings per share impact for the two projects in 2019 is expected to exceed $0.20 a share. But the final amount recorded this year will depend on the timing of the actual transfer of control of each of the assets. Now on Slide 11, concerning our Vineyard Wind 800 megawatt offshore wind farm in joint venture with Copenhagen Infrastructure Partners, the Bureau of Ocean Energy Management or BOEM determined the need to file a Supplemental Environmental Impact Study to complete a revised cumulative impact. This review affects all offshore wind projects on the Atlantic coast and is not specific to our project. We expect the BOEM to complete the Supplemental Environmental Impact Study by end of 2019 early 2020. And then the final Record of Decision by early second quarter 2020. Although no formal schedule has been issued. The project has recently completed other permitting milestones including the settlement agreement Edgartown Conservation Commission on the export cable route to allow an undersea transmission corridor to connect the offshore wind farm with the mainland electric grid. In addition the project has a strong support of key stakeholders, multiple initiatives from governor, senators, industry associations, the BOEM, and supply chain have urged Department of Interior to expedite the Vineyard Wind's Record of Decision. Vineyard Wind is targeting a commission date by the end of 2022 subject to BOEM permitting clearance by early 2020. Since the business case is being impacted by external delays we are requesting an extension from the IRS for the originally planned ITCs of the project. We are considering technology improvements including larger rotors that would supplement the business case. In offshore wind, on Slide 12, Vineyard Wind submitted bids to Massachusetts second offshore wind RFP and to the Connecticut's offshore wind RFPs. Vineyard Wind holds two leases in Massachusetts that could accommodate up to three gigawatts and two gigawatts, respectively and keep in mind, our share of this is 50%. These sites are owned jointly with CIP. In Connecticut, Vineyard Wind submitted bids to the RFP including a required 400-megawatt plan and options for 800 megawatts, 1,000 megawatts, and 1,200 megawatts. The winning bid is expected to be selected in November. Now, the project will reduce regional greenhouse gas emissions by over 1.6 million tons per year and generate up to $1.6 billion in direct economic benefits and save ratepayers up to $1.1 billion in energy costs. Now, we did announce a partnership with Marmon Utility LLC to create the first Tier 1 offshore wind supplier in the U.S. to supply offshore inter-array cable cores. We proposed significant workforce development initiatives, pilot programs, and research for up to $26.5 million to establish Bridgeport as an offshore wind hub and many more collaborative activities with Connecticut partners. The earliest COD is expected in 2024. While Massachusetts Vineyard Wind also submitted bids into the Massachusetts second offshore wind RFP with the required proposal of 400 megawatts and two options of 800 megawatts. The selection is expected to be announced November 8th. Now, the proposals include significant job creation and port infrastructure investment opportunities. Turning now to slide 13. Our -- it shows an update on our Forward 2020+ plan. We're on track to achieve savings in the range of $70 million to $85 million pre-tax in 2019 of which 35% would come from Corporate, 30% from Networks and the remaining 35% from Renewables. In the first nine months, we achieved about $45 million driven by spend management initiatives to about 54%, savings have also been delivered through the optimization of the spans of control in our organizational structure, additional labor capitalization, the transition to a co-source model for tax and wind availability improvements. Now we're also implementing robotic process automation, automating processes in our billing front office, credit and collection departments. Which will both reduce our cost and enhance service to our customers and most of these will be reflected in 2020 and beyond. Year-to-date Renewables achieved 40% of the $45 million pre-tax savings and Networks 60% including the allocation from Corporate. By quarter, 45% were delivered in the third quarter and 55% in the first six months of the year. On slide 14. In conclusion, we continue to execute on our long-term strategy to deliver sustainable growth by investing in clean energy as we build the grid of the future and serve our customers through innovative and smarter energy solutions. We are focused on our core regulated and contracted businesses and we continue to maintain a strong balance sheet while we execute programs like Forward 2020+ for best-in-class operational efficiency. And now I'm going to turn it over to Doug Stuver our CFO.

Thank you, Jim. Good morning, everyone and thank you for joining us today. I'm now on slide 16, which shows our quarterly and nine months year-to-date roll forward earnings per share from 2018 to 2019 on a U.S. GAAP basis and on a non-U.S. GAAP adjusted basis. In these periods, the adjusted earnings per share largely reflects the exclusion of positive mark-to-market adjustments in the Renewables segment, which resulted from favorable price movements on our merchant hedges in the quarter and the year-to-date period. In the quarter this item was a positive $0.10 to our U.S. GAAP results and for the year-to-date period was $0.16 positive. Accelerated depreciation from repowering of certain wind projects which as Jim noted is progressing ahead of our strategic targets had positive adjustments of $0.01 quarter-over-quarter and $0.04 year-over-year. Other impacts include those Jim has noted and are also described in the appendix. As you can see on both the U.S. GAAP and adjusted basis Networks results for the quarterly and year-to-date roll forward are lower reflecting higher outage restoration and staging costs and the effects of depreciation expense outpacing rate increases. Renewables results improved in the quarter-over-quarter comparison due to stronger wind resource and production from the addition of the Patriot Wind farm at the end of the second quarter. On a comparative basis year-over-year, however, Renewables earnings per share declined as a result of poor wind resource and negative impacts from extreme weather primarily in the first quarter of the year. Corporate's results are lower in the third quarter comparison reflecting the issuance of a new Green Bond in the second quarter of 2019 as well as the impact of the consolidating tax rate adjustment. On the next several slides, we'll provide more detail on the business segment impacts. Moving to slide 2017, this summarizes the results and key drivers for the Networks business. For Networks, you can see that the third quarter 2019 adjusted earnings per share of $0.29 was lower by $0.02 compared to the third quarter of 2018. In the quarter-over-quarter, comparison there was a small benefit of $0.01 due to new rate years in our Connecticut and Massachusetts utilities offsetting this increase was greater depreciation due to the fixed assets placed in service as we successfully execute on our capital investment plan. For the first nine months of 2019, the Networks business reported adjusted earnings per share of $1.15, a decline of $0.07 compared to the first nine months of 2018. Similar to the quarterly year-over-year comparison the nine-month year-over-year comparison reflects additional earnings attributed to rate increases from the negative impact of depreciation of on new assets. In addition, it reflects a $0.03 year-over-year increase in outage restoration and staging costs. This outage restoration category represents the costs principally over time in contractors to restore service to customers from outages caused by aged equipment principally in New York and from minor storms. The outages from aged equipment were a larger issue in the third quarter than we've previously experienced. We're addressing the staging and outage restoration cost impacts in our pending rate filings in New York and Maine as Jim mentioned earlier. And just to repeat the impacts of that using the recovery provisions proposed by staff if we were to incur the same level of costs as this year's cost to date once new rates are in effect we would have recovered approximately 90% of those costs. Now moving to slide 18. We also provide the results and key drivers for the Renewables segment. While the Renewables segment was a key driver for the year-over-year decline in earnings as I noted earlier improved wind production resulted in a positive quarter-over-quarter impact. In addition, compared to our expectations wind production was 11% below for the first nine months of 2019 and approximately 7% lower for the third quarter of 2019 driven by delays in new construction and installation of boost software for existing facilities along with wind resource and external factors such as icing on the blades and access to sites in the earlier part of the year. Wind resource is approximately 4% lower than expectations for the year but 3% positive for the quarter compared to our expectations. I'm happy to state for the fourth quarter, we're off to a good start with our production. Production right now is slightly ahead of our expectations through yesterday. Looking at the key drivers of the year-over-year comparisons, in the third quarter of 2019 the Renewables segment produced a positive adjusted earnings per share of $0.15, which was a $0.04 improvement versus the third quarter of 2018. Quarter-over-quarter Renewables earnings improved with higher wind production from existing assets as well as from the addition of the Patriot and Montague wind farms, wind production in total was approximately 12% higher quarter-over-quarter reflecting improvements in the Northeast and the South Texas regions with a total benefit of $0.06 over the period. Also positively impacting the quarterly comparison were incremental production tax credits due to the improved wind performance in 2019, along with thermal and trading revenue and minority interest related to our tax equity financing. Renewables results were negatively impacted in the third quarter by pricing impacts, largely driven by the change in status of projects that moved from contracted to merchant as well as the non-recurring positive impacts in the third quarter of 2018 from bankruptcy related collateral proceeds and a claim sale which had about a $0.05 negative impact on the year-over-year comparison. For the nine months of the year, the Renewables segment reported adjusted EPS of $0.37, a decline of $0.10 compared to the first nine months of 2018. Impacts for the nine-month year-over-year comparison are similar to those impacting the third quarter comparison, although significantly impacted by the low wind production in the first quarter. The nine-month year-over-year negative variance for wind production of existing assets however was offset by the additional production from new assets. Pricing for the nine-month year-over-year comparison was significantly negative in part due to lower merchant pricing and unfavorable RECs along with status changes from power purchase agreements to merchant and the 2018 benefits from the FirstEnergy Solutions, bankruptcy claims sale and collateral. Finally PTCs for the nine-month year-over-year comparison reflected the net negative impact of our expiring PTCs. Partially offsetting these negative impacts were the Klamath’s optimization and trading margins that resulted from continued higher prices and volatility in the northwest with the exceptionally cold winter and the ongoing impact of the repair of the Canadian pipeline rupture along with improved minority interest. Moving to Slide 2019. We show our Corporate results. The Corporate segment reported adjusted EPS for the third quarter of negative $0.04, a decline of $0.07 quarter-over-quarter. The decline primarily reflects the additional interest expense from the $750 million Green Bonds that we issued in May at an interest rate of 3.8%. For the first nine months of the year, Corporate reported a loss of $0.09, which was $0.05 lower than the same period in 2018. The nine months year-over-year comparison included positive tax impacts that were due to a positive discrete tax item in the first quarter and a favorable year-over-year change in the consolidating tax rate adjustment as well as the impact of the Green Bond issuance. AVANGRID's consolidated effective tax rate before discrete items for the first nine months of the year is approximately 19.4% and that's largely in line with the rate through June. Moving to Slide 20, we show our guidance ranges broken down by big business segment for 2019. On a consolidated basis, we revised earnings per share guidance upward to $2.36 per share to $2.46 per share for U.S. GAAP, and as Jim noted, this reflects the favorable mark-to-market impacts and Renewables in the third quarter and we have affirmed the adjusted earnings per share guidance of $2.25 to $2.35. For Networks, while we had positive impacts from the mid-period assessment savings of $0.07 for the first nine months of the year, we're adjusting the guidance range to reflect the continued costs we're seeing related to outage restoration costs, primarily related to the greater instances of equipment faults and failures that we've experienced in the third quarter and are estimating to continue in the fourth quarter. Outage restoration plus staging costs were $0.03 negative and $0.09 unfavorable to our expectations for the third quarter and first nine months of 2019 respectively. Importantly, we've been addressing these outage restoration and staging cost impacts in our New York and Maine rate cases, which Jim and I have covered earlier in our commentary. In our Renewables business segment, we're increasing our guidance, as we expect our pending sale of Dry Lake II and Copper Crossing together to deliver over $0.20 per share. This is above the high end of our $0.05 to $0.10 target for 2019. The sale is subject to FERC approval and we expect the transaction to close in December. Earnings recognition is tied to the timing of transfer of control for each project and we presently expect the controllable transfer for both in the fourth quarter of 2019. We've also experienced good wind results in the third quarter and as I noted earlier through October. Forward 2020+ mid-period assessment savings for the quarter were approximately $0.01 and for the nine months of the year were approximately $0.04. Finally, we're bringing down the Corporate segment to reflect the ongoing impact of interest expense and our current expectations including tax impacts for the year considering our actual results year-to-date as well as allowing for a range of risk around our fourth quarter tax true-ups. That said it's important to also acknowledge that our performance versus our guidance over the remainder of 2019 assumes risks and opportunities, as Jim noted earlier. And within the Networks guidance we have the pending FERC ROE decision as part of that which is estimated at $0.09 per share -- or sorry, $0.06 per share. Moving to slide 21, we show our credit ratings. Those remain strong and we highlight the year-to-date actions taken by the rating agencies including upgrades at CMP, UI and SEG. We also highlight our green financing strategy including the $1.35 billion of Green Bonds outstanding and our $2.5 billion sustainability linked credit facility. This green financing strategy has helped to finance our growth in our strategic plan. We're on track with our capital plans for 2019, and in the first nine months of 2019, we spent nearly $2.2 billion in CapEx, which is over a 90% increase for the first nine months of 2018. The significant increase in investment is important to our future growth and in delivering safe and reliable service to our customers. On the next slide, we wanted to highlight that we continue to pursue our sustainability objectives and support the United Nations' Sustainable Development Goals with a main focus in everything that we do on number 7 Affordable and Clean Energy and number 13 Climate Action. We also have direct contributions to number 6 Clean Water and Sanitation, number 9 Industry Innovation and Infrastructure, number 15 Life on Land and number 17 Partnerships for the Goals. We also recapped that we've made ambitious in sector-leading carbon reduction pledges including a target of carbon neutrality by 2035. Thank you. And with that, I'll now hand the call back to our operator Jason for questions.

[Operator Instructions] Our first question comes from the line of Praful Mehta from Citigroup. Your line is open.

Thanks for the question. So, just firstly wanted to understand, in terms of the earnings for the quarter, how much actually was the impact from the storms to the Networks business. Can you just breakout exactly what was that impact that you're saying 90% of which can be recovered in future depending on what you get with New York. But if you can break out that storm impact, that would be really helpful.

Yeah. So this is Doug, Praful. For the quarter, we were about $0.03 unfavorable to our expectations with storms and staging impacts. And I should say also that we really think of this as more than minor storms. There's also equipment failures and the cost to restore that. So, we've kind of broadened the category as to how we speak of this as outage restoration and staging costs as a combined category. In the quarter, we saw a decrease in staging costs, but we saw an overall increase in our outage restoration costs. Year-to-date, we're at roughly $42 million of total costs for that category.

I got you. And even in your year-end or your 2019 estimates, what is built into that? And is that entire number also going to be recoverable at 90% pro forma for what you get in outcome in New York?

Yeah. We do -- Praful, this is Jim. We will -- we fully expect the 90% to include the full year. And Doug will have to give you what we -- I don't know what we estimate. I don't think we've estimated much more for the rest of the year other than what we had originally thought. So, yeah, I mean we have a continuation of it yet, because we're expecting more storms. So, yeah.

If you think about just last year Praful, we were at roughly $0.14 all in with the impacts of storms and staging costs, and through the third quarter of last year we were at roughly $0.09. So in the fourth quarter of last year, we had roughly an additional $0.05 per share. And in terms of how we're thinking about the guidance for Q4, it's largely consistent with that type of profile. What we've seen this year unfortunately, we’re anticipating those costs to go down and roughly be half of 2018 levels. And instead, we've seen a net higher incidence this year. So, we're looking forward to the rate cases as a way to help close those gaps.

And Praful, this is Bob. I'll also say that when we look at these numbers, the vast majority of the instances we've had where we've incurred cost beyond what's currently reflected in rates is at NYSEG, NYSEG's Electric business. Rochester continues to perform very well, electric and gas, NYSEG Gas. We've seen some increase at CMP as well. But as Jim and Doug both said, we think with the -- what's been negotiated so far and where we are in the case right now in staff's position both as it relates to CMP and NYSEG Electric that we would see much, much better performance in terms of recovering these types of costs. If you think about the experience for example in 2018 that we had at NYSEG 2018 is the test year in this case. So that provides a basis for a much higher elevated level of recovery for storms than we had in the past.

Got you. That's super helpful detail. Then maybe just a second question more strategic. There have been talk of M&A in the space? And also there have been some rumors around your name. And I know Iberdrola is, obviously, going to have a view on that as well. But from an AVANGRID perspective and if AVANGRID currency were to be used in a transaction what are the criteria from your perspective that you consider when you think about M&A? Like is there a particular set of things that need to be achieved in your mind, or is this the right time to do something or not? How should we think about that more from a broad strategic perspective as you think about our AVANGRID currency and where you are today?

Well, first off we're not going to comment on any rumors or speculation on anything. And to the extent as we've said in the past, we're focused on our organic and strategic growth. Ibedrola does look at things all the time. And we have a strong currency in AVANGRID. So -- but as I said we're not going to comment on anything related to any rumors at this point.

Fair enough. I just wanted to confirm, so from your perspective you think AVANGRID today has a strong currency if it were to be utilized?

We have good currency, yeah.

All right. Really appreciate it guys. Thank you.

Your next question comes from the line of Insoo Kim from Goldman Sachs. Your line is open.

Thank you. Thinking about the EPS benefit from the renewable asset sales and partnerships that you are expected to achieve in 2019. How should we think about the timing of that and the amounts that we should expect in 2020 versus what you guys had guided at the beginning of the year?

We expect the transaction with action to close in the fourth quarter. It depends on when we recognize the gain depends on when the change of control for each farm, the wind farm and the solar farm actually occurs. If the change of control occurs in this year then we could recognize the gain this year and we're expecting the gain to be in excess of $0.20 a share for the two. Going forward, we've settled -- we didn't include in our long-term outlook that we did in February this year. We didn't include anything beyond 2019 but we said we thought there could be $0.05 to $0.10 a share in ongoing sale of development projects and assets to recycle capital in our renewable business that would allow us then to optimize our portfolio, which is really going to be an ongoing practice of ours and strategy. That as we see development opportunities to sell those or even existing assets where we're getting value in excess of what we value it for then we would be inclined to sell it and so we're going to continue to do that. And we see that as ongoing. We have such a large pipeline of projects right now that it just makes sense for us to be recycling the capital as we move forward.

Understood. And I recognize that I think that was guided as an upside to your guidance. So that's still the way you would think about it in terms of your guidance, and what the asset sales partnership would contribute on top of that in 2020 and beyond. But it's not embedded in the base plan?

Yeah, we won't change what we're looking at for the longer-term outlook until we actually talk about it after the end of this year.

Understood. And switching over to the regulated rate base figures, you guys did a very detailed job in all of your fact books laying out the various assumptions and estimates for rate base across the different utilities over a multiyear period. Especially when it comes to New York and with the rate case that's been filed and the numbers that have been filed by both the utility and what the staff has come out with. It's been a little bit tough to reconcile the estimates especially in New York of what's in the fact books versus the numbers that we have seen in the filings. How should we think about what's included in those slide decks versus what's in the rate case? And does your growth in networks over the multiyear period utilize achieving the ROEs using the rate base that are in these presentations?

First off on the ROE what we said in our long-term outlook back in February that we would intend to earn the allowed ROEs except in 2019, because we knew we were filing rate cases in New York. So New York would -- be there. What we have in the fact book and what the commission's staff came out with as far as additions to rate base, we're in settlement discussions right now. So, obviously, the number is going to change from what they said and what we put in and we'll update that as we go forward and as we get the results of the rate case. And hopefully, we get a settlement that's a long-term settlement with -- in New York. So we'll update that as things progress. I don't know Bob or Doug do you want to add anything?

Exactly right.

Understood. I think just versus what you had even filed on the utility side, there may have been a difference in numbers, but I could follow-up with that offline. Thank you very much.

Your next question comes from the line of Mr. Greg Gordon from Evercore ISI. Your line is open.

Thanks. Good morning.

Good morning.

Good morning. A bunch of my key questions were answered. Can you explain the adjustment from GAAP to operating earnings as it relates to accelerated depreciation, how that's coming about and why we should consider that non-operating? And will there be as you pursue your strategy going forward on repowering the potential for future adjustments of that nature?

Yeah. The adjustment that we made was strictly for the repowering asset and knowing that this was really going to be pretty much a one-time issue. We're not -- we see the repowering occurring this year with the benefits occurring in 2020 when the assets will actually get repowered. So we had to accelerate the depreciation on those once we decided to do the repowering. And so we had to reflect that in 2019, so that was really it. And there's -- those assets that are going to be repowered, we just see that as the 370 or so megawatts we're doing that's pretty much it for now. And so I don't know Doug you want to add or…

Yeah. The only thing I'd add is just to be clear when we're talking about accelerated depreciation it's just on the nacelle component itself. It's not all of the assets of the wind farm our repowerings are basically putting a new nacelle and blades on the existing tower and foundation. So, we're basically just taking accelerated depreciation to remove that category of the assets off the books by the time the repowering takes place.

Okay. And then I guess the other question just going back to Vineyard Wind. You said you've got the settlement now with Edgartown, but can you just go over again what the puts and takes are that you're thinking about in terms of potentially not getting the full tax credit benefits, but what you can do in the business planning for that asset to try to get back inside the range of your expected IRR outcomes when you -- because when you initially built it or said you were going to build that you thought you were going to be getting different tax attributes?

Well, we originally said that we were looking at having the first 400 megawatts coming online in 2021, which would have given us the 24% ITC and the second 400 coming on in 2022, which would have been the 18%. So what we are doing right now is we're meeting with the IRS to talk to them about getting an extension since the basis for us not being able to get it done in 2021 really because of the delays in the federal government and the Department of Interior wanting to take a cumulative impact look at all wind farms that are going to be built on offshore in the North Atlanta. So when we made our original proposal and when we applied for the permit from BOEM, we were really the only one. And so they were looking at it as a one-off. Now that there are so many projects being involved, they want to make sure they're all going to be designed and aligned consistently. So, with that, some or the other things so we're petitioning IRS to get an extension of that ITC at the 24% level for -- through into the 2022 time frame. Now the other things we're looking at. One is, as there's a delay we have the opportunity to get a larger rotor going from the 164 meter rotor to 174 meters. We also then when you look at the way that configuration could be if we end up with the one nautical miles spacing on an east to west configuration. And that's what the Fisherman want and that seems to be where things may be heading, there's a less wake effect for us in that regard. So that actually can improve the capacity factor a little bit. So there are other things we're looking at technically and from an engineering standpoint that would actually improve the return somewhat. But the real thrust is to work with the IRS and see about getting some type of extension.

Great. Thank you very much.

You’re welcome.

Your next question comes from the line of Mr. Michael Sullivan from Wolfe Research. Your line is open.

Hey, Good morning.

Hey, Michael.

Hey, so I first just wanted to clarify and start with the Renewables segment guidance, so you took the midpoint up there by $0.15 to the positive. You've got the asset sales that you're doing, which I think you're saying you're going to exceed $0.20. What are the other moving pieces there that are offsetting that?

Well probably the other one is, we're seeing some positive movement in the wind itself, the wind resource at least in October is up a little bit over our expectations. But it's mainly looking at the asset sales, I guess this is a primary one. And really also we'd already factored in our Forward 2020+ plan, that's impacting Renewables and the availability for Renewables is actually improved as a result of that plan that we've been working on. So we're seeing the availability it actually is a little better. So there's a combination of things, but mainly it's the asset sales.

Okay. Those are more positives so why is the segment guidance going up less than just the pure asset sale benefit?

It's up I think just looking at previous to current it's up $0.14. And so...

We had 5% in there.

Right exactly. We had 5% in there and we didn't take it all the way because we're not totally sure, it's going to close and that both projects will end up in the -- being able to be consolidated. So or deconsolidated I should say and the change of control would have to occur. So we're being a little conservative on it. But I think we're in a good range right now.

Okay. And then just on the Vineyard Wind project and the remaining permitting process from here? I just wanted to make sure, so once we get the draft Supplemental EIS and that goes out for comment. What is the expected timeline from there before that ultimately gets finalized?

Yes. Maybe since Alejandro is on the line, maybe he can talk about what's going on with Vineyard Wind since he's our resident expert.

Good morning everyone. Thank you, Jim. So I mean the process is that once the environmental impact statement gets out, it will go for public comments. So there is a period for public comment. And then after that the BOEM has to issue the final environmental impact statement. So once the draft is out there, we think that in a period of about a couple of months BOEM should be able to issue the final environmental impact statement. So everything relies on when BOEM is able to issue that draft environmental impact statement which as has been commented requires that the cumulative impact study is done. So this is actually the most critical part of the process and the one that is less clear in terms of timing.

Okay. Thank you.

Your next question comes from the line of Sophie Karp from KeyBanc. Your line is open.

Hi, good morning. A lot of my questions have been answered, but I just wanted to ask maybe a couple of questions on the Renewables. First on slide 36 there's -- I'm looking at RECs pricing here it, seems like there's a decent degree of volatility in those. And I was just wondering, if that's something that you've looked at potentially selling off or hedging or doing something with them? And what is -- how do you think about that in general?

Yes these are our - basically our merchant RECs. We have other RECs that are part of our power purchase agreement. So this is just breaking out the standalone RECs. And yes as you've noted we have seen a decline in prices in 2019 versus last year and in terms of our strategy for RECs we're always looking at the forward market and opportunities to basically sell those forward. We do have contracts in place going out say one to two years with already committed sale of those RECs. We don't actually transfer title until that point in time. So the effects of those forward commitments would already basically be locked in and eligible for recognition in the future. But -- so I guess the short answer is but yes we do already look on a forward basis and sell a portion of those RECs forward as the opportunity presents.

Is there a market or an opportunity to just sell them I guess completely at the point when you originate the asset or something along those lines?

That market typically is more of just the power purchase agreements themselves where you tend to bundle the RECs with the energy there's also the California market where a portion of these reside and you can again bundle them with energy or sell them on a standalone basis. But typically what you're describing is more what would exist in a power purchase agreement, where as you generate the title essentially immediately passes to the offtaker.

Got it. And my second question is for Alejandro, maybe just congrats on your role and as you begin to spend more time here in the U.S. working with agencies here and on the projects here, what have you – have you been learning so far and maybe what surprised you compared to your prior experiences in Europe?

Thank you very much. Well, I mean, I have been here for a couple of years already leading the offshore business. So the U.S. is not new to me. But it's clear that in the new role I will have much more exposure to everything related to investor relations. So that is a part that I have to get to learn in the coming months. So I'm really looking forward to that.

Thank you.

Your next question comes from the line of Julien Dumoulin-Smith from Bank of America. Your line is open. Julien Dumoulin-Smith: Hey, good morning team.

Good morning.

Good morning. Julien Dumoulin-Smith: So a quick perhaps a little bit more of a accounting item here. On the FERC ROE assumption I think you guys had $0.06, how do you think about that given just how late we are in the year, would you think about rolling that into next year, if we don't get FERC action? And then I suppose the real question is, do you have thoughts about mitigating that? Or is this really a function of the range that you already provide to account for things like this?

Well you're right it is late in the year. They are from what we understand the new commissioner Stanley has a hearing set I think they set it for November 5. So he could become a commissioner. Yes. But the possibility it's still in our guidance at this point. To the extent they get it this year, it would be great. If it doesn't occur this year then hopefully we would see an action next year, because it's only been going on since 2011. So I think eight years, it's kind of a long time to wait for an ROE decision, so yes we wouldn't reflect whatever occurs or doesn't occur this year in the guidance now or changes into next year when we look at guidance overall for next year.

The other thing to add to that is that there's about $0.01 per share of ongoing impact from that. So as time passes and this backlog accumulates that would then grow the impact when it ultimately is resolved. Julien Dumoulin-Smith: Got it. Okay, excellent. And then just if I can follow-up a little bit more on the Renewables guidance shift from sort of down versus initial guidance to up. Seeing that now versus the original 2019 guidance you're about $0.10 higher that seems to reconcile with the fact that you've $0.05 to $0.10 of asset sale assumptions originally and now it looks like you're heading towards $0.20. So moving from $0.10 to $0.20 would seem to account for the positive delta versus the initial guidance. But I just wanted to understand now that we've added sort of the onetimes into the number, how do we think about the reasons behind the negative adjustments early in the year. I think Sophie started to allude to this earlier, but I just want to sure we're kind of calibrating appropriately here.

Yes, earlier in the year keep in mind we saw wind resource was negative to our expectations as was production. So those were both down. So that's why we move things down and at the time when we were looking at -- we had -- in our plan $0.05 to $0.10 a share for asset sales. So now that we actually have a signed agreement that we expect to close on in the fourth quarter we have a better sense of what the gains might be in this year. And so we could reflect that better. So really the downward adjustment we made earlier was really just reflective of the resource and production we saw in the first half of the year.

I would also say that increased visibility through the summer of the impact of our mid-period assessment and the efficiencies coming out of that. And the amount of that that would be attributable to Renewables also helped in terms of our views now towards the end of the year.

And part of that was the increase in availability we saw starting at about the mid- part of the year when the plans that were executed put in place to get the higher availability actually have taken -- come to fruition and we're seeing it now. Julien Dumoulin-Smith: So perhaps if I can clarify this very quickly. You're saying that some of the pressures that materialized in the first half of the year with respect to capacity factors and otherwise have fundamentally in part been reversed in the back half based on some of the factors that you talked about?

I'd say the availability has improved which helps that. We saw in the third quarter the wind resource was actually solid. It was good. It was slightly above our expectation. We're seeing October is slightly above our expectations. So we're seeing some trend towards improvement in the wind resource, but we're not predicting that it's going to keep that way. I mean we're keeping to our original plan for the last couple of months for the year. And so those are the things we saw.

I'd just add -- this is Doug, Julian that if you just look at kind of our quarter-by-quarter progression of wind production, in the first quarter we were down 14% year-over-year. In the second quarter, we were down 5% cumulatively year-over-year. And in the third quarter we're basically flat year-over-year. So we've seen over time an improvement in the wind production year-over-year. So that helps to I think explain why in the early part of the year we had -- we went to the direction of lowering guidance for Renewables. And then as we got better line of sight to the opportunities with our strategic partnerships and the value that that could bring to 2019. That, along with the improved wind conditions, helped to kind of move the guidance in the opposite direction. Julien Dumoulin-Smith: All right. Fair enough guys. Thank you very much. Have a great day.

Yes. You too.

The next question comes from the line of Mr. Paul Patterson from Glenrock Associates. Your line is open.

Hey, good morning, guys.

Hi, Paul.

Good morning

As you guys I'm sure have noticed, Ørsted came out with an announcement yesterday. And I was wondering just how you guys view that in terms of its applicability or lack thereof with you guys?

Yes. You're talking about the thing they mentioned on the blocking and the wake effect. Keep in mind that Iberdrola and AVANGRID's predecessors have been operating wind farms for 20 years. And so, we have some extensive experience in how we operate wind farms. And this wake effect, we've factored that in for a number of years, based on the experience that we have with Iberdrola on onshore wind and then also with the offshore wind, now that they've had. But really the expertise that has been developed over the last 20 years and the engineering that they've been able to do and analysis has shown us that there is a wake effect and there is a blocking effect and we factor that into the analysis that we do and we've been doing it for a number of years. As matter of fact, we don't use a P50 when we're doing an analysis of our investments. We use P60, P65, P70 depending on where the asset is located. So this was -- we've known about this for a long time.

Yes.

But not a surprise.

The other thing I think is important to recognize is that, Iberdrola's experience with its offshore wind farms in Europe is that the actual wind they've experienced has exceeded their initial estimates within their investment dossier. So I think it just goes again to point out that I think the way we have forecasted wind has been pretty accurate from an offshore perspective.

Okay. Awesome. And then, just a follow-up on Greg Gordon's question. On the IRS extension application. Just what would happen if that -- what would be the impact if you didn't get the extension I guess.

Well, if we didn't get the extension -- keep in mind, our original assumption was that half of the wind farm, 400 megawatts and we have half of that, was going to get to 24%, if it got in 2021. Right now we're targeting to get to work with BOEM, so that we can have the production initiated in 2022 for the full wind farm. So you'd be going -- if nothing else happens, you'd be going from 24% to 18% on the 400 megawatts.

Okay. I appreciate. Thanks so much, guys. Hang in there.

Okay.

Thank you.

Your next question comes from the line of Martin Young from Investec. Your line is open.

Yes. Good morning to everybody. And a couple of questions, if I may, please. The first is just a follow-up on the blocking and wake effects. In respect of your suggestions that you could increase the rotor size on Vineyard Wind. Does that increase blocking and wake effects and to what extent have you factored that into your analysis? And then, the second question is more of a sort of a high-level strategic question about the business, what sort of longer-term Networks, Renewables split do you feel happy with? And are there any areas of your business that you would put in the -- that could do better box? Thanks.

All we were saying is because of the change that we're anticipating will occur by moving to a one nautical mile spacing on the turbines, that it would lessen the wake effect. So we could potentially improve the capacity -- net capacity factor for each turbine. So that's really what we're talking about. And we're looking at that right now depending on how the spacing ends up working with BOEM.

But does moving from 164 to 174 meter rotors, increase wake blocking? Or doesn't make that difference?

I'd have to ask our engineer Alejandro should know it.

Yes, Jim. So I mean, when you do the wind analysis, obviously, you run the model again with the new turbine type. And you have to recalculate every single variable of it. So, the general answer to that would be, yes, the bigger the rotor, the bigger the wake effect. But it is not actually that straightforward. For example, a bigger rotor means a higher hub height. And higher hub heights mean a lower wake effect. So, there are a lot of variables into the model. You cannot isolate them. The answer to that would be, putting all the variables into the equation, a bigger rotor gives you a higher production. And then, splitting that high production whether it is because of the size of the rotor, the wake effect, the height of the hub et cetera, et cetera, is more complicated. But the general answer is 174 will certainly give a high production than 164.

Okay, very clear thanks.

And your second question on the split between Renewables and the Networks business, our long-term projections had it maintained in the 75, 25 split through 2022. We don't see that appreciably changing, because of the growth we have in both Networks and Renewables. So -- and we haven't necessarily targeted any specific number, it's where the opportunities lie and that we will then focus on, for each business and so -- but in that split that's -- we don't feel pretty comfortable with that as a range.

And anything you would hold your hands up and say, it could be in a -- could do better and needs to be better area of the business at this stage?

This is Bob. I guess I would say continue to look at ways of derisking the business, both on Networks and in Renewables. So on Networks we've talked about, what we've experienced over the past couple of years, on storms in trouble. And I think we're addressing that in these rate cases. We're doing a comprehensive look on the Renewables side, as well, let's say, how, can we further derisk the business. We love both pieces of the business, but we're recognized that there's some inherent risks that we need to figure out how we can reduce.

Okay. Thank you.

Your next question comes from the line of Insoo Kim from Goldman Sachs. Your line is open.

Thanks. My follow-up questions have been answered. Thank you very much.

All right, thanks.

Thanks, Insoo.

I am showing no further questions at this time. Please continue speakers.

Okay. Well thank you everybody for participating. If you have more detailed questions you wish to follow-up with our Investor Relations team, please do so. And thank you for, being here today.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. And have a wonderful day. You may all disconnect.