Good day, ladies and gentlemen. Thank you for standing by, and welcome to the Q1 2019 Avangrid, Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will follow at that time. [Operator Instructions] As a reminder, this conference may be reocrded. I’ll now turn the conference over to our host Patricia Cosgel, Vice President of Investor and Shareholder Relations. You may begin.

Thank you, Olivia, and good morning to everyone. Thank you for joining us to discuss Avangrid’s first 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 on the call to answer your questions. If you do not have a copy of our press release or presentation for today’s call, they are available on our website at www.avangrid.com. During today’s call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995 based on current expectations and assumptions, which are subject to risks and uncertainties. Actual results could differ materially from our forward-looking statements, if any of our key assumptions are incorrect or because of other factors discussed in Avangrid’s earnings news release, in the comments made during 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.

Okay. Thanks, Patricia, and good morning, everybody. And I want to thank everybody for joining us this morning. The start of 2019 really has been pretty good for Avangrid in terms of execution on our strategic plan. And the first quarter earnings were in line with expectations after taking into account the significant below normal wind conditions that we experienced. Our net income for the quarter was $217 million or $0.70 per share. The adjusted net income amounted to $219 million or $0.71 per share. Now, we continue to successfully execute on our strategic plan on our renewables and transmission projects are nearly 1 gigawatt of renewable assets under construction is on track to come online in 2019. Our New England Clean Energy Connect transmission project is on track and recently received the Maine Public Utility Commission Certificate of Public Convenience and Necessity, a 900 megawatt AC project from the New York Transco was selected by NYISO to provide transfer capability from the Albany area, through the Hudson Valley region and Avangrid networks investment is about $120 million or will be in that project. Our Vineyard Wind offshore project is also on track with nearly 70% of the supply chain secured and recently, it received the Massachusetts Department of Public Utilities approval of contracts with the electric distribution companies. In the renewables business, we’ve increased our pipeline by 1.6 gigawatts to 15.4 gigawatts and did execute an additional contract for 58 megawatts with the expansion of an onshore wind project. In addition, the Board on April 11 declared a quarterly dividend of $0.44 per share payable in July 1. Turning to Slide 6, for the quarter, GAAP earnings per share was $0.70, down $0.09 or 11% versus the first quarter of 2018 and adjusted earnings per share was $0.71, down $0.07 or 9% versus the first quarter of 2018. Other key drivers for the quarter-over-quarter results by business are really – when you look at networks, adjusted earnings per share for the first quarter of 2019 is flat versus 2018 at about $0.65 per share. The positive contributions from our multi-year rate plans was partially offset by the impact of higher depreciation. We also had positive earnings sharing adjustment in 2018 that impacts the comparison, when you look at the quarter-over-quarter by about [indiscernible] storm-related activity and really we’re talking about the minor storms had an impact, very similar to what we saw in the first quarter of 2018. Actually, it’s probably about $0.01 more expense we incurred. And we called it in the guidance we gave for year-end 2019, that includes half of the extraordinary impact recorded in 2018, which was about $0.14 a share in 2018, so we are considering about $0.07 would occur in 2019. And right now we’re running a little bit above that – ahead of that with about $0.04 impact for the quarter, when you look at the total versus our expectation. In renewables, the adjusted earnings per share decreased by $0.13 to $0.02 per share and that was affected by really significant lower wind production. If we were down 14% year-over-year and it was really 17% below our expectations. And as was anticipated back in February and then really confirmed by our operational data published two weeks ago on our website and I want to add a little more color, when you look at February, had never really recovered and we ended up, down about 18% in production. And then in March, it continued being down being down about 15% of production. And when you look at the wind resource, it’s been below normal in all regions, but really more significantly in the West, where the production in the quarter has been 34% lower than last year and that’s the lowest wind resource in the last 10 years. In addition, we had some extreme weather conditions in some areas of the Midwest and Northeast that impacted all the assets in the area, exceptionally low temperatures, which were below our minimum operating range, we had ice on blades and problems accessing the site because of the snow, which really limited the performance of some of our assets. Now, our assets are all in good shape. They’re running well now, because the spring is here. But some of these negative aspects were factored into our guidance, but not all, so the year-over-year comparison was also affected by the expiration of some PTCs and lower REC revenues, which again the PTCs we knew were coming off and REC prices were a little lower. And that was partially offset by – we really had some higher revenues from our Klamath Cogeneration Facility and then power trading. The corporate adjusted earnings per share increased $0.06 to $0.04 a share and really that was the tax benefit item. So we are affirming today, our consolidated 2019 earnings guidance of $2.18 to $2.33 in earnings per share and $2.25 to $2.40 in adjusted earnings per share. Adjusted renewables range we’re lowering by $0.04, a share downward to really reflect the wind resources in the first quarter and really so far in April. April’s down of almost 8% through the first part of April. And then we increased corporate by $0.03 to really reflect the state tax benefits that we’re seeing that weren’t in our original guidance. And as we also mentioned in our fourth quarter, 2018 earnings call, we are actively engaged with the consultant to gain efficiencies that should mitigate over the balance of 2019, the negative impacts from below the expected wind resources that we realized in the first quarter. Now moving to Slide 7 to the highlights from our Network business, when you look at New York, we expect to file a rate cases for NYSEG and RGE by the end of May for new tariffs, it should be effective in the second quarter of 2020. In these filings, we plan to request a cycle vegetation maintenance program at NYSEG and recovery for resiliency investments. Also in New York, the 2017 storm settlement was approved, which included a $3.9 million commitment to increased storm hardening and resiliency and improve our customer communication initiatives and assistance. These were largely completed already in 2018. And the New York Commission issued an order to several New York utilities, NYSEG and RGE included to show-cause for 2018 really directing the companies to respond to the New York PSC’s staff storm investigation and potential violations to emergency response plans, regulations, and orders. In addition, the New York Commission issued an order directing the commencement of judicial enforcement proceedings for NYSEG. In Maine, Central Maine Power, there is an ongoing rate case for which we expect a decision in the fourth quarter of 2019 and other regulatory items, we’re watching include the FERC’s decision the New England transmission ROE proceedings, in which the Commission proposed a method for calculating ROE, which resulted in a 10.41 base ROE. Our views are in line with the other New England TOs, who were generally supportive of the methodology. And since this order, we’ve actually requested FERC to dismiss complaints two through four. Separately, we tracking FERC’s inquiry into the transmission rate incentives and how of the New England TO ROE methodology would apply to other transmission facilities. Now moving on to our Networks projects. Central Maine’s Powers New England Clean Energy Connect or NECEC is on track and received a Certificate of Public Convenience and Necessity from the Maine PUC on April 19. Other stages of the approval process are underway at the Maine Department of Environment Protection, the Maine Land Use Planning Commission and the Army Corps of Engineers. Public hearings will conclude in early May with decisions expected in late 2019. In addition, we’ve already done the EPC contract for the high-voltage DC converter and that was recently awarded. In New York, New York ISO approved a proposal from the New York Transco for an AC transmission project called New York Energy Solution. Now, Avangrid Networks owns 20% in the New York Transco and our estimated investment the project is a $120 million. The New York Energy Solution project will increase the transfer capability from the Albany region through the Hudson Valley by about 900 megawatt through existing right of ways and it’s scheduled to be in service in December of 2023. Now, this project replaces transmission assets that are about 90 or 80 years old and will enable surplus clean-energy resources in upstate New York to help the state achieve its energy goals. In Maine, through our MEPCO transmission project, we completed the rebuild of a 46-year old structures along the 50-mile 345 kV circuit and it came in well under budget. Now on Slide 9 in renewables, we are successfully implementing our strategic plan with 1 gigawatt of onshore wind projects under construction and are on track to be operational in 2019, in which tax equity financing is currently being negotiated. Also in the first quarter, we executed a new offshore wind PPA for the 58 megawatt extension of the Tatanka Ridge project in South Dakota. With that, we have secured 550 megawatts of wind and solar projects for COD in 2020 and we’ve already exceeded our long-term goal for renewables contracted growth by 2022. Moreover, we have increased our pipeline from 13.8 gigawatt to 15.4 gigawatt. Now, this breaks down into 6 gigawatts of onshore wind, 4.4 gigawatts of solar and 5 gigawatts of offshore wind, now that includes the 2.5 gigawatts for Kitty Hawk, 1.5 gigawatts for our 50% share of Vineyard Wind, and 1 gigawatt for our new lease off the coast of Massachusetts. In addition, we continue to move forward in optimization and monetization of our pipeline, including various ongoing negotiations on asset sales and potential partners, some of which we really expect to close this year. Now on Slide 10, Vineyard Wind, which is our 800 megawatt offshore wind farm in joint venture with Copenhagen Infrastructure Partners is on track and continues to advance the permitting process. This year, the final environmental impact report was certified by the Commonwealth of Massachusetts. And in March, Vineyard Wind received a positive consistency review to the federal permitting process from the Rhode Island Coastal Resource Management Council. And this filed positives report – support from the Fisheries Advisory Board of Rhode Island. In April, Vineyard Wind received approval from the Massachusetts DPUC of the contracts with the electric distribution companies. Now moving forward, the final Environmental Impact Statement is expected to be completed in June and the record of decision is targeted for August. And we expect to receive all permits and approvals by year-end 2019. In addition, we selected suppliers for over 70% of the project capital expenditures, including the offshore wind turbines with fastest 9.5 megawatt. Now, we see a strong interest for the financial community, part of the first offshore wind project including the banks and tax equity investors. Now, we are targeting to have all 800 megawatts in operation by the end of 2021. That would have a positive impact to the earnings, really about $0.01 a share assuming we can spread the ITC over the life of the project, which is the 20 years. Additionally, Vineyard Wind submitted a bid in the New York’s first offshore Wind RFP with its Liberty Wind project in order to contribute to the New York State goal of installing 9,000 megawatts of offshore wind by 2035. This proposal includes options for 400, 800 and 1200 megawatts with a robust direct transmission proposal the Long Island with high economic value to the region. Vineyard Wind is partnering with transmission developer, Anbaric, who will finance and own the transmission. NYSERDA plans to announce the winner this spring. Vineyard Wind also submitted bids into the Rhode Island renewables RFPs with proposals of 200 megawatts and 300 megawatts each and then the selection of bidders is expected in May. Massachusetts announced its second 800 megawatt offshore wind RFP with bids due in August and selection in November. Now on Slide 11, there’s an overview of a very important initiative we have ongoing. We’ve performed a mid-period assessment of our Forward 2020 plan for achieving best-in-class efficiency. Now through this organization wide review, we’re identifying both near and long-term opportunities, including process, organizational and technology initiatives to improve our performance. We’ve identified best practices for our service delivery models in corporate functions and operations. And we are evaluating and optimizing our systems and processes to identify causes, and in cases that we can have for automation and remove duplication of activities and eliminating unnecessary reporting. For 2019 alone, we’ve identified 10 business cases for automation, in billing, front office, and credit and collection departments and we’ve already started implementations there. We’re optimizing our operating expense spend by scrutinizing contract and through strategic sourcing events, we’re implementing government best practices to ensure our processes for capturing those savings are sustainable going forward. We looked rather closely at our organizational structure and how we benchmark against our peer group. What we found was that there is an opportunity to drive agility and improve productivity and efficiency. This will drive quicker decision making and greater empowerment and accountability. And we’re reviewing our real estate portfolio to ensure the use of our facilities is optimized. Revenue enhancing initiatives such as increasing our wind energetic availability have also been identified through the project and are being implemented now. So we’ve successfully identified and launched targeted initiatives and we are moving quickly to implement these optimizations and best practices, which will mitigate costs and deliver sustainable value. Moving to Slide 12, in summary, with projects like the Mid Period Assessment and all that we have ongoing in our networks and renewal businesses, Avangrid is on target to meet expectations. We’re focused on our core regulated and contracted businesses and we continue to maintain a very strong balance sheet, while we work toward best-in-class operational efficiencies. We’ll continue to focus on delivering clean-energy solutions, as we build the grid of the future, and take care of our customers through excellent customer service and ever smarter energy solutions. We’re fulfilling our strategy to deliver sustainable growth by investing in a smarter and cleaner energy future. And now, I’m going to turn it over to our CFO, Doug Stuver, to talk about the financial aspects.

Thank you, Jim. Good morning everyone and thank you for joining us today. I’m now on Slide 14. On this slide, we roll forward earnings per share from the first quarter of 2018 to the same period in 2019 on a GAAP basis and on a non-GAAP U.S. adjusted basis. Adjusted EPS reflects the exclusion of mark-to-market adjustments in the renewable segment, restructuring charges and adjustments related to our prior ownership of gas storage and trading businesses, which we exited in 2018. The combined impact of which was minimal on a quarter-over-quarter basis. As you can see on a GAAP and adjusted basis, networks results for the quarter are flat compared to the first quarter of 2018 and corporate is up $0.06. Renewables is down $0.15 on a GAAP basis and down $0.13 on an adjusted basis. Renewables, as Jim noted, was significantly impacted in the first quarter from low wind production compared to 2018, reflecting lower than expected wind resource and the impacts of storms and severe weather. Wind production for the first quarter of 2019 was also below our expectations. We had higher corporate earnings in the quarter-over-quarter period due to favorable tax impacts, which partially offset the renewables impacts. Now in the next several slides, I’ll provide some more detail on these business segment impacts. I’m now on Slide 15. This shows the results and key drivers for Networks, Renewables, and Corporate. For the first quarter, you can see that Networks results as I mentioned were flat quarter-over-quarter with $201 million of adjusted net income and $0.65 earnings per share. While we experienced the benefit of $0.04 quarter-over-quarter, due to new rates going into effect for several of our utilities, this benefit was offset by a $0.02 negative impact from higher depreciation due to higher fixed asset levels in service and a $0.02 earnings sharing benefit detriment in the first quarter – that occurred in the first quarter of 2018 and did not recur in 2019. So that was a period-over-period negative. As Jim noted, while minor non-deferrable storms were not a factor quarter-over-quarter, the Networks business continued to experience storm activity in the first quarter of 2019. Major deferrable storms were not as significant as in 2018 and minor non-deferrable storms had an impact of approximately $0.04 negative, which is approximately $0.01 higher than the first quarter of 2018. As Jim noted, we included in our guidance for 2019 an estimate for minor storms of about $0.07 and that was about half of our 2018 experience. Minor storm impacts include the direct cost of minor storms, as well as the related effects, the capitalized labor and AFUDC, when resources are diverted from capital activities to perform storm recovery. As I mentioned earlier, our Renewable segment was the key driver for the quarter-over-quarter decline in earnings. Renewables adjusted net income declined by $42 million over the period or $0.13 per share. Performance period-over-period was significantly impacted by 14% lower wind production and that would be 14.7% when you include our joint venture projects in that calculation. This lower wind production explained over half of the decline and contributed $0.07 negative impact. Low wind resource was the primary driver, resulting in a quarter-over-quarter decline of approximately 610 gigawatt hours, followed by weather impacts, which caused a further 119 gigawatt hour decline. As Jim noted, the Western region was hit hardest with a 34% quarter-over-quarter decline in production. Wind production also for the quarter was 17% below our expectations. About 70% of that downside was poor wind resource and then the remainder was attributed to external factors such as the significant weather that caused icing on the blades and heavy snowfall that prevented access to some of our sites. The Western and Mid-Continent regions explain most of the wind production under performance compared to our expectations with the West, driven by poor wind resource and Mid-Continent due to lower wind resource and severe weather impacts. In addition, other wind-related impacts mainly PTC roll-off and lower renewable energy credits sales contributed a $0.06 negative impact to the quarter-over-quarter variances. Minority interest earnings, taxes, and various other items also reduced 2019 quarter-over-quarter earnings. These items were partially offset in Renewables by $0.04 quarter-over-quarter benefit and that came from optimizing the Klamath, Oregon generation plants and our trading revenues. We had high prices in the West and higher volatility in the West due to the exceptionally cold winter, plus we had the ongoing impact of the Canadian pipeline rupture that was driving up prices. Finally, the Corporate segment reported $13 million of adjusted net income or $0.04 per share. This is a $0.06 improvement quarter-over-quarter, corporate income taxes for the first quarter of 2019, include an $11 million favorable discrete item, pertaining to the state income tax, net operating loss, carry-forward, and a $12 million favorable consolidating tax rate adjustment. This tax adjustment aligns the consolidated income tax expense with some of the income taxes for the Networks and Renewables segments. For the first quarter, Avangrid’s consolidated effective tax rate was approximately 19.5% before discrete items. Now moving to Slide 16, we’ll get into some of the Renewables production drivers. Slide 16 covers the net capacity factors. As you can see on this slide, the wind net capacity factor was 28.1% in the first quarter compared to 33.6% in the first quarter of 2018% or 16% quarter-over-quarter decline. Our annual and quarterly net capacity factors clearly demonstrates the recent negative trends in wind including compared to our revised forecast. As you’re aware, this year we revised our methodology for forecasting wind, previously using an average of 2011 to 2014 and now using life-to-date average on a plant-by-plant basis. In the top right quadrant of this slide, you can also see that the recent years remain below average, in addition, the bottom chart which shows our historical quarterly performance demonstrates that the first quarter of 2019 was below the life-to-date average. Now moving to Slide 17, we note that our wind production is 14% lower quarter-over-quarter, predominantly in the West, which had a 34% decline and in the Mid-Continent, which had an 18% decline. The primary factor driving the decline in the West was low wind resource; while in the Mid-Continent, it was severe weather that caused icing on the blades and restricted access to our facilities. The bottom portion of this chart shows Bonneville Power Administration generation and over the period from 2010 to 2019, there you can see that the first quarter of 2019 was a 10-year low in terms of generation for Bonneville Power Administration and kind of correlated well with what we saw in the West with our assets. Now moving to Slide 18. We further highlight the impacts on wind production related to external factors such as storms and icing, with those impacts, mostly in the Mid-Continent and Northeast. As you can see on the left side of the chart, the first quarter 2019 gigawatt hours lost to these external causes was 87% higher than in 2018. Icing on the blades negatively impacted generation in the first quarter by 80 gigawatt hours and that’s over double the impact in the first quarter of 2018. Other external factors, the other portion of that bar graph that includes mainly site access limitations caused by severe weather, turbine shutdowns to prevent weather-related damage, and also other weather-related items such as low temperatures that prevent our field technicians from accessing the site. In terms of the pricing now, moving to Slide 19, you can see here a decline in the average price quarter-over-quarter and that’s largely due to lower REC sales and pricing on REC sales as well as the impact of expiring PPAs. Moving to Slide 20, our credit ratings remained strong and we highlight the recent upgrades of the United Illuminating Company and Southern Connecticut Gas Company to an A minus, as well as the affirmation of Avangrid and the other utility subsidiary ratings by Fitch. Our dividend policy remains unchanged, targeting 65% to 75% of net income. And as Jim noted, the Board recently approved a quarterly dividend payable July 1. Now moving to Slide 21, we affirm our consolidated 2019 earnings per share guidance of $2.18 to $2.33 per share and adjusted earnings per share guidance of $2.25 to $2.40. We have revised our guidance for two of our business segments and that’s primarily based on our first quarter performance, as Jim noted and Renewables considering the negative impacts in the first quarter from wind resource and weather, we reduced our ranges by $0.04, so that the EPS range under U.S. GAAP to renewables is now $0.41 to $0.49 and the adjusted earnings per share range is $0.48 to $0.56 per share. In our February earnings call, we noted the poor wind resource for January compared to expectations and we intend to make up those impacts over the full calendar year through cost efficiencies. As Jim noted, those negative impacts continued and the total impact for the quarter is 17% below expectations as I noted earlier. Also, Jim mentioned in April, we’ve seen continued downside with production about 8%, below the life-to-date average. In corporate, I noted earlier, we had a positive state tax benefit, and that was not considered in our guidance. So that allowed us to improve our earnings per share and adjusted earnings per share upward by $0.03 to a minus $0.05 to positive $0.01. As Jim noted, the lower wind resource has been a drag on our first quarter results and has exceeded our expectations. However, we are confident the work we’re doing with our Forward 2020 and the Mid Period Assessment will deliver savings over the balance of 2019 that overcome these negative first quarter wind impacts. That said, it’s also important to acknowledge that our guidance over the remainder of 2019 assumes a return of wind resources to our historical life-to-date average and that we have limited capability to further offset those continued impacts of poor wind resource like we saw in the first quarter. Our 2019 guidance also assumes a favorable outcome of the FERC ROE complaint that’s pending, that has approximately $0.06 per share assumed benefit. Also, the sale of projects and strategic partnerships in renewables, let’s assume that between $0.05 and $0.10 per share positive and then the storm impacts in Networks are assumed at roughly a $0.07 negative per share impact, which is half of 2018 levels. Moving now to Slide 22. We have our company highlights here. We certainly have attractive investment opportunities in our Networks business and our Renewables business, as Jim noted, and we’ve made significant advances this quarter in our New England Clean Energy projects. Our leadership in offshore wind in the U.S. with access to three lease areas now provides significant value and diversification to our business. Our commitment to sustainability is also very important to us and we want to emphasize our long-term target of achieving carbon neutrality by 2035. Importantly, we have a distinctively strong balance sheet and solid investment grade credit ratings and a commitment to increase our dividend in line with our 65% to 75% target payout ratio. Thank you, everyone. And I’ll now hand the call back to our operator, Olivia, for questions.

Thank you. [Operator Instructions] Now first question coming from the line of Praful Mehta with Citigroup. Your line is now open.

Thanks so much. Hi guys.

Hi, Praful.

Hi, so maybe just starting off with the key topic around wind and the disappointment on the capacity factors. It is surprising given you’d reset the capacity factors recently at the Analyst Day. So just trying to understand what caught you by surprise so incrementally following the Analyst Day that wasn’t foreseen in terms of wind capacity factor results that you now see?

Yes. Praful, the main thing was that the wind resource and the production was down even more wind for the rest of February than in the March. So it ended up being down as Doug said 17% for the quarter in production. Now the wind resource itself was the biggest part of that and the other things, we had icing and so forth, but still we never would have projected to be down 15% from what we consider the life-to-date average and for the entire quarter. And so that’s why we brought it down initially as everybody noted, and then we just had a continuation of very, very poor wind conditions and wind resources for across – almost across the country, but really in the West and the Midwest and a little bit more the Northeast, that just continued throughout the quarter. And so – and then when we got to the first part of April, it’s down almost 8% through the first half of the month. So we said it does – we cannot justify not reducing the renewable piece, a little bit going for the rest of the year. And so that’s – we just wouldn’t predict that we’d be down that much every month in the quarter. So that’s what caused it. Now Laura, if you want to add anything else.

No. I think that’s exactly right, Jim.

Got it. That’s helpful color, Jim. But again, if you look on Slide 16, if we look at the capacity factors that you’re showing over the last, I guess starting 2011, there seems to be a clear trend down starting 15 in terms of capacity factors. So I guess the question is, is the expectation that is being set in, even with the new bar that you’d now have post Analyst Day appropriate or is that still too high? How do we get comfortable as investors that the set is now accurate or the bar that you’ve built into your forecast is now accurate versus what you’re currently seeing on the ground?

Yes. I think we’ll continue to evaluate this, but when we look at the life-to-date of the wind resources, you’re going to have, I would say ups and downs normally. The last four, five years have been below that average. And when you look at the previous few years, they were above that, so we have to look at the life that they figure out what it’s going to do. Now, wind conditions are going to fluctuate and change; hopefully, it goes back up. Laura, you may want to address this and how you see it goes, it’s hard to – it’s difficult to predict other than looking at history and saying what is history telling us and what we see going forward now we can look at wind patterns, we can look at changes, we have meteorologists on staff look at all these things, and they’re telling us, this is the best forecast we could do, so.

Absolutely. I agree with that, Jim. Historical life-to-date feels to be the best metric that we can use. There is always going to be uncertainty in forecast. And for this particular Q1 in addition to the wind resource and you’ve seen the charts, even the independent charts that were provided for the Columbia Gorge by Bonneville, it really was just an exceptional low year, hopefully a tail event for that particular resource. But also in the Midwest, we had such extreme weather that that was an additional factor that really impacted us more than we’ve seen in previous years. So there’s definitely efforts ongoing with our technical teams to explore options for deicing of blades and what other things can we doing proactively given that extreme weather is pending to have an impact on our fleet.

Got you. Thank you. And then, just one quick follow-up on the partnership and asset sales. Jim, you mentioned that you’re hoping to have something done this year. It sounded like if there are any other color or context you can give around it? Is it still the development pipeline that you’re looking to monetize or is there anything else that we should be thinking about on that front?

It’s the development pipeline in total and we’re negotiating with a number of parties right now and looking at various projects. So we would expect to be able to have something. As we said, we are targeting some sales every year going forward to make sure we’re monetizing the pipeline and doing looking at what is in the best interest of the company. If we can get a better net present value by selling it and not retaining it and developing ourselves, that’s exactly what we’re going to do. So as I said, we have a number of opportunities, we’re pursuing right now. So we would expect something by the end of the year.

Got you. Appreciate it, guys. Thank you.

Thanks, Praful.

And our next question coming from the line of Julien Dumoulin-Smith from Bank of America. Your line is now open. Julien Dumoulin-Smith: Hey, good morning. Can you hear me?

Yes. We can hear you, Julien.

Hi, good morning, Julien. Julien Dumoulin-Smith: Hey, good morning, everyone. So perhaps just to come back to the New York update real quickly. Can you talk a little bit about the storm response and how that reconciles of the rate case here. Obviously, we’ve seen an uptick in spend from kind of off late, but I was sort of curious because you’ve already talked about upping the spend in response to some of the storms. So how could we see that evolve here in the rate case and as a result of some of the latest developments in New York and what they said?

Yes. Well, we laid out the resiliency plan that we’ve talked about and that’s going to be part of our rate case. And I’ll let Bob, he can fill you in on what we’re doing right now.

Thanks, Jim. Good morning. So a couple of things, when you look at what the staff highlights in the results of their investigation into 2018 storms. I would put them in a number of pockets. One, is around storm preparation in particular around resources both internal resources, as well as the mutual assistance process. Another one would be around resources associated with wire guard damage assessors. Third would be around how utilities communicate with their customers, local community leaders, regulators, life support customers, and the like. And then the last one is around, as Jim said, really resiliency. And I would include within that not only investments in the system to harden the system, but also very importantly vegetation management policies and practices. So post the storms in 2018, many of which occurred in the first quarter and the first half of the second quarter. We started our own assessment and quite frankly, many of these areas in terms of things, we could do to improve on our storm response. And as Jim mentioned, I think the first visible item was the resiliency plan that we came out with in June, which is a $2.5 billion plan, $2 billion of which is dedicated towards New York, $0.5 billion of that is AMI, $0.5 billion is vegetation management and the remainder being true resiliency type investments. But throughout the year, we did a lot also in terms of preparation for storm in terms of assessing our resource plans, in terms of human capital, communications and the like. So when we look at the recommendations that came out of the staff’s investigation, we already are well down the road on addressing many of them. So that will be our response. Specific to your question, however, I will say that within their analysis, they fully recognize and are recommending that companies address what is the new norm for storms with resiliency type investments, including vegetation management and we feel it’s very important as well AMI. And so this is something we were planning on putting in our filings that we’re going to make in May anyway, but I think it’s clear from staff’s own report, they see the importance of these types of investments to helping utilities, one ensure that their system holds up better in a storm, but then two, allows them to respond more quickly from a restoration perspective. Julien Dumoulin-Smith: Excellent. And also just a little detail here on the $0.03 tax benefit – state tax benefit, how much of that is an ongoing item, just as we think about fine-tuning things?

Yes. I honestly don’t think of that, Julien as an ongoing item. That was a discrete item, basically a change in apportionment among the states that had a higher allocation domain and due to the unique kind of tax treatment of NOLs in Maine and the high tax rate in Maine, it gave an improvement to our the value of our net operating loss carry-forwards. Julien Dumoulin-Smith: Excellent, thank you all very much. Talk to you soon.

Okay. Thanks, Julien.

Our next question coming from the line of Greg Gordon with Evercore ISI. Your line is now open.

Thanks, good morning.

Hi, Greg.

Can you just reiterate for me, you said that you budgeted $0.07 this year for minor storms, which was obviously a reduction from what you experienced last year and how much of that was lack of a better term eaten up in Q1?

Yes. Greg, it’s Bob. So the way I look at it is we – when we look at the first quarter of this year, to last year, overall I would say we saw less major storms, but the frequency of either threatened or minor storms was as much as if not greater than last year in the first quarter. And so what we’re seeing is the expectations of greater staging of resources in advance of a storm. It’s those are the types of costs that we’re currently incurring that are above and beyond for example in New York what we currently have reflected in rates, which is an agreement that was reached four years ago. So I would say that for Q1 this year, our overall costs are relatively on par non-deferrable costs to last year and into it several pennies $0.02 or $0.03 into that $0.07 cushion, but I personally remain very confident that in the overall guidance of Networks for calendar year 2019.

Either way, it’s good that you’re making progress with the regulators to fix the problem, so.

Yes. This will be a big part as I mentioned in Julien’s question of our rate cases. I think it’s – we recognize that the expectations of customers, local community leaders, politicians, regulators is that we are ready for and respond rapidly to storms when they incur and we’re doing that. Obviously, there is a cost associated with that and that will be addressed in the rate cases.

Got you. Next question, depending on how I look at the right-hand box on Page 15, there was either $0.13 or $0.15 of headwind, if I include minority interest or exclude basically this way, from wind production other win and things like that and you’ve only lowered guidance in the range by $0.04. So I mean arithmetically, does that mean that you think you’ve found between $0.09 and $0.11 of offsets through the programs you’re putting in flight and that will actually impact this year?

I’ll just start by saying it. Keep in mind that some of these are year-over-year impacts that were already contemplated, not entirely unpredictable. For example, production tax credit expiration. That’s a negative impact year-over-year and that’s really a function of just reaching year 11 of the life of a wind farm and no longer qualifying for production tax credits in that year. So not all of that impact really is driving negative against our guidance. And so to more broadly answer your question, yes, we feel like we have other offsets that we can achieve within renewables to help minimize those overall impacts.

That’s a great clarification. I get that and that’s fair. We can talk offline about that what subset of these is the – or if you have it on hand. That’s fine. What subset of the $0.15 was unexpected versus expected, but the short answer is, you’ve put programs in place to offset all but $0.04 of that.

Yes. And Greg, let me just add, the plan we have and with the consultant we’re using. We fully expect to be able to offset the downside in the first quarter from the wind resource negativity we saw. We expect we have a fully offset now, it’s going to come into other areas, not necessarily all in renewables. So we’ll see that and then again, the cost reductions gets spread to renewables and the networks as we go through. But as I said, we fully expect the offset that fully.

Okay. And my final question is when I think about the Klamath optimization and trading, I mean it really is – it’s a non-recurring opportunity, but really that opportunity is a function of the same issues, which caused headwinds in that region.

Absolutely.

So, it’s kind of like a dirty hedge, so that reverses is going forward, the problems also reverse. And so, I see that as one – almost as dirty hedge to the things that caused the problems on the wind side in the first place. Does that seem like a reasonable summary?

Yes. The way to look at it is since wind production was down so much, it gave us an opportunity to run our gas plants to generate more electricity to be sold and the prices were attractive because of the pipeline outage that was in Canada as well, which restricted the gas supply into the area. So there are a lot of things going on that allowed us to have some benefit from Klamath. And but you’re right, I mean, if wind production were back up to where it would be, we wouldn’t be running the plant as much. And so yes, Laura, you want to add something.

No. Absolutely agree with that, and you’re absolutely right. Low wind was a large contributor to the situation that occurred in the West that gave opportunity for us. But as you know, we’re a physical player in the West and so we are optimizing a book. And the combination of low wind in those extremely high gas prices and the fact that we were able to optimize transmission gave us a nice portfolio of tools to be able to offset some of the losses that we suffered due to low wind resource.

Great. Thanks, team. Take care.

Thanks, Greg.

Thank you.

Our next question coming from the line of Chris Turnure with JPMorgan. Your line is now open.

Good morning. I just had a, I think pretty quick modeling question probably for Bob. Could you remind us over the past maybe two or three years, what you booked for a refund to customers at New York Networks. My understanding is there is a year that ends in May of every year, where you look at your earned returns within the bands and then at some point after that, you book a refund to customers, and I think that goes into your adjusted EPS?

Yes. I mean we do look at. Yes, the earning share in calculation referring to is done on a rate-year basis, which is basically May-to-May. For what period are you looking for to in terms of what our actual returns were versus, I mean, I think some of that we have in our fact book, but if you’re looking for specific dollars of what we deferred in years that we over earned and I can get you that information by rate-year.

Yes. I mean I’m interested in the details, but just at least directionally, kind of what were you booking in the past two or three years there?

Yes. I’ll – let us give you some specific numbers back. I would say in general, it’s the gas businesses, my recollection of generally over earned, the electric depending on the year have been a mix. If you look at our fact book, I think it’s like Page 62, you will see in there, the returns, those are after sharing returns. So we can give you a sense for where we shared. But again, what I’ll do is, I’ll get back to you with the actual dollars. I think you’re looking for the actual dollars, correct?

That’s correct. And then I think you mentioned or Doug, you mentioned in the script that there was an impact year-over-year in the first quarter of this year from Networks as a result of not having a cost of sharing being booked.

Yes, I think what happened is there, sometimes Chris, as you know, because the test is a rate year test that doesn’t overlay with the calendar year. We will make estimates at the end of a calendar year for accounting purposes of what we think sharing will be, but obviously that has to get trued up, either in the first quarter or early second quarter to reflect what we ultimately do have for sharing for that rate year. So that we typically make some of those adjustments in Q1, because we start to get better visibility into what the rate year earnings will look like us as compared to the calendar year.

Just to that point. So in Q1 of 2018 that was a benefit.

Right, right. We essentially over approved at the end of calendar year 2017 for what was then rate year two earnings that accompanies and some of that reversed.

Okay. And then presumably flowing from that and the year that ended May of 2018, I guess, you didn’t earn into the bands at all, so you did not book anything this quarter?

Well, we don’t know that yet, because we haven’t finished the third rate year, in terms of exactly. But as of this point, there weren’t any issues in the first quarter that would have had us change or lower the estimate we had as of the end of 2018 for a rate year three earnings sharing.

Okay. I’ll probably follow-up online for some more detail, but thank you for that clarification.

Sure.

Our next question coming from the line of Michael Sullivan with Wolfe Research. Your line is now open.

Yes. Hey, guys, good morning.

Hey, Michael.

I just wanted to clarify on the guidance range. So just kind of with some of the headwinds you talked about in Q1 and then what you’re seeing in April. And then some of the offsets that you’ve talked about is the midpoint of the range still the right place to be thinking about. Or are you now seeing some movement within that range for the year.

No. We’re still saying the range for adjusted earnings of $2.25 to $2.40. I mean, we’re still looking at that range, and we feel pretty good about that.

Okay. And then just specifically at the corporate segment, I was just looking back over the past couple of years and that really seems to move around. You guys have moved the range a lot each year and there seems to be these tax items that sort of pop-up every quarter. And I’m just wondering, if there’s anything on a go forward basis that that you guys can – that can be done to sort of normalize or move things out, because it really just seems to vary a lot.

Yes. I’ll just kind of start, on an annual basis, I would say probably the biggest driver for that is the apportionment among our states and whatever impacts those have by shifting our taxable income. We operate in many states, I believe, almost 30 and each, obviously, has different tax rates. So it’s difficult to manage or predict throughout the year, where that apportionment will land and that’s normally is a fourth quarter adjustment. So I will say though this year, two things. One, we’ve implemented new software in 2018 that both helped us remediate the material weakness that we had and puts us on a much better footing going forward to have. I’ll say more stable and predictable tax results. So that tool, I believe will help to smooth out those impacts over time, but I think there still can be some variability.

Yes. And Michael, one of the things that occurred in this quarter was by allocating the apportionment put more taxable income in the Maine, which has a higher tax rate than in other jurisdictions, which then we get more of our NOLs being utilized in Maine to offset some of that. So that’s why we end up with a tax benefit there. So it depends, as Doug was saying, it depends on which jurisdiction has the more taxable income and how this all gets apportion. So we don’t really know that when you look at every state we’re in until late in the year. So we recognize, it’s kind of a problem for you guys to model, but it’s also difficult for us to predict, where it ends up based on what income is derived in which state and what apportionment that is required by each state in the unitary taxes in some states and not others. So I know it’s complicated and we’re trying to smooth this out as best we can.

Okay. I appreciate all the color on that. And then just my last one is on the Vineyard Wind project. It sounds like you guys are a little more confident on the margin that you are going to be able to get the whole thing into service in 2021. Just from a financial standpoint, was a little surprised why getting the higher ITC a year earlier only has a – I think you said, $0.01 impact. And then also just wondering at what – where do you need to get in this project to the point, where you may be able to give us some more guidance on the actual earnings contribution of the project as a whole?

Yes. I think we are pretty confident of the ITC impact. You got to remember that’s just the impact, the benefit for us and it’s on the margin. When you look at, it’s just a shift from the 18% of the 24 for half of the project and half of that we get. So, it ends up being kind of small, but still $0.01, so $3 million tax benefit for us. Laura, you may want to talk about how you see the project.

Just a little additional color on that. From my perspective, the first 400 megawatt initially were targeted for the end of 2021, and then we had targeted May-June for the second. So it’s really not a full-year impact and then as Jim and Doug mentioned, it’s of course 50% of our share. From a permitting perspective, we are expecting the final Federal permit at the end of the summer. And I think at that point, we’ll feel very confident in our ability to be able to move forward with the construction program as planned.

I think the key is, right now we’re targeting to get it all in 2021. That’s really the plan now. But we have a backup that if that doesn’t occur, then we can still look at all the options of when – how to maximize the ITC will get from the full project.

Great, thank you.

Thanks, Michael.

Our next question coming from the line of Angie Storozynski from Macquarie. Your line is open.

Thank you. I have a question about potential changes to the Jones Act. I understand that those are more related to natural gas supply for weather in Puerto Rico. But I’m just wondering if that could somehow positively approve also to offshore and project development in New England?

Yes. Angie, from what we understand the changes the President suggesting for the Jones Act are – would provide only for access to the LNG to be brought into the state. We haven’t seen anything yet that would apply to the offshore wind. However, we would love to see that change. And I think we’re pursuing with as we speak with people in Congress, and with the administration, we do bring that up that it would help facilitate the offshore wind business if we can get an exemption from the Jones Act. So – but right now from what we’ve seen, it doesn’t – it won’t have a positive impact for us.

And as I’m sure you’re aware, our construction plan anticipates compliance with the Jones Act and we’ve been planning for that all along.

Okay. And then, back to that $0.01 earnings contribution. So that $0.01 assumes just like you mentioned more the that is going to be half-year contribution of the first half [indiscernible] and just marginal contribution from the remaining for 100, right. So what if I were to just look at the annual contribution of these assets, if they were to the operational side flow content have been in 12 how much would that be?

Yes. So let me just clarify a little bit. So when Jim talked about the $0.01 that’s basically looking at the ITC benefits and did contribution to earnings by moving that forward one year and upsizing the level of the ITC. We’re basically at an average right now of 21%, when you think of two phases, one at 18% and one at 24%. So by taking it all to 24%, that would deliver roughly a $0.01 per share positive impact from the ITC, assuming that that ITC gets spread over the life project. And that’s also subject to some uncertainty, because we’re using tax equity and actually the terms of the tax equity financing will help dictate what that recognition period will be. So I’d say that $0.01 benefit that Jim described is probably the minimum just related to the ITC impact. There will also be all the other impacts of having the project in service, a year earlier and getting the full benefits of its operation. So that piece is not part of this $0.01, it would be further additive.

So when are going to know, obviously the remaining factor here for this entire project to come online by 2021. Is there any specific permit that we need to look forward? That’s actually going to determine this earlier COD?

Angie, we’re having a hard time hearing you. There’s a lot of static on the phone. I think what you were asking is permit limitations to be able to get to 2021. I think, as Laura suggests that we should have the federal permits by the end of this summer. And we can then readily determine if we are going to be able to meet everything by 2021. We’re making great progress with the suppliers. And as I said we got about 70% of all of the supplies we’re going to need or under being contracted now. So we’re in pretty good shape from that standpoint. We feel very confident about getting the permits that we need. So I think, the 2021 is realistic, it’s just assuming things fall in line with the rest of this year. And by the end of the summer, we should have a really good sense that 2021, we can get everything in by that point in time, if not as I said, we’ll have a backup plan that maximizes the ITC and the production, we’re going to derive from the project.

Okay. Thank you.

Thanks, Angie.

And our next question coming from the line of Phil Covello with ExodusPoint. Your line is now open.

Hey, guys. It’s Andy Levi. How you doing? Just a few follow-up questions. Just on the corporate side, so what’s the total annual impact and is it just taxes that you optimized if you know better way to put it, or is there anything else in there. So I came up with like $0.07 that I gathered with your guidance.

There’s really two things going on in corporate, both tax related. One is the state tax, NOL item that I mentioned on some of the earlier questions. And then there’s also a consolidating rate adjustments that we do in corporate that basically outlines the overall effective tax rate of Avangrid and the income tax expense at that level for the some of the income tax expense for the other segment. So that piece of it actually will just reverse over the course of the year. By the end of the year, there is no need to further balance all the individual segments that just resolves itself. So that particular item was about $12 million after tax impact to corporate. The other item this state allocation and the NOL was $11 million item.

But you’re right. It’s about $0.07.

Yes. Okay. And that’s all one-time in nature, right.

Well, yes, the state NOL item is one-time in nature. This consolidating tax rate item is something that we generally have throughout the year and then it reverses by the end of the year. In all cases, it would smooth out.

Okay. Could think corporate change by like $0.06 or $0.07 versus the guidance?

No. We move the guidance by $0.03.

I thought, it was more. Okay, I guess the range, maybe. Okay, so – and then just understand like your commentary on the year. So if I kind of go back and look at the transcript basically what you’re saying is that if you have a – from April on or May on, if the wind is normal and everything kind of else goes right at the utility, you should be able to stay within your range, but if not there could be an issue.

Yes. Our assumption is that we will be able to mitigate the first quarter from the wind with the cost savings, we’re going to be putting in and efficiencies. And that – and you’re right going forward, if we have, let’s say, 15% production decline over the rest of the year, which would be unheard of that would be challenging for us.

But even if it was 5% below normal, that would be challenging? I guess, right?

Yes. I mean, but it’s not as quite a significant, but yes.

Well, obviously. Yes.

And there are all kinds of factors we put in for those – when we looked at the guidance that Doug had gone through.

I’m sorry, go ahead.

No, that’s it.

Okay. And then on the cost savings initiative, could you just tell us what business lines that’s occurring on. Is that happening at both – is it happening in the Renewable business. Is it happening on the wind side and corporate? Can you just give us a little color of just the areas and then I have a follow-up to that.

It’s really across the board, Andy. It’s at corporate networks and Renewables and we’re looking at all areas as to how to get efficiencies and improve in every area. So, it’s really across the board. It’s not isolated to one area or another.

And will most of the savings come at the utility or will it come from renewables and corporate.

There is going to be a mix and then even corporate – but keep in mind corporate gets allocated to the businesses. So on saving there we’ll move down to Networks and Renewables.

Thank you. And ladies and gentlemen, we are now out of time. I would like to turn the call back over to Mr. Jim Torgerson for closing remarks.

Okay. Well, thank you everybody for participating. I know, we run out of time here. So if you have further questions, please don’t hesitate to call our Investor Relations team. And I think the bottom line is we had some challenges from the wind resources, but everything is really on track for our businesses overall. And I think, we are very confident with the performance of our businesses going forward and with the projects that we have, particularly the large projects, the NECEC and the Vineyard Wind, we’re very confident that those are going to be very successful. So with that, I want to thank you all for participating today and have a great day. Thank you.

Ladies and gentlemen, thank you for your participation in today’s conference. This does conclude the program and you may now disconnect. Good day.