Patricia Cosgel - Vice President of Investor and Shareholder Relations James Torgerson - Chief Executive Officer Richard Nicholas - Senior Vice President and Chief Financial Officer Frank Burkhartsmeyer - President and Chief Executive Officer of Avangrid Renewables

Joe Zhou - Avon Capital Advisors, LLC Christopher Turnure - JPMorgan Chase & Co. Sophie Karp - Guggenheim Securities Andrew Levi - Avon Capital Advisors, LLC Glen Pruitt - Wells Fargo Securities Paul Patterson - Glenrock Associates LLC

Welcome to the Avangrid Third Quarter 2016 Earnings Call. I will now turn the call over to your host, Patricia Cosgel.

Thank you, Danielle, and good morning to everyone. Thank you for joining us to discuss Avangrid’s third quarter 2016 earnings results. Presenting on the call today are Jim Torgerson, our Chief Executive Officer; and Rich Nicholas, our Chief Financial Officer. Robert Kump, our Chief Executive Officer of Avangrid Network; and Frank Burkhartsmeyer, our Chief Executive Officer of Avangrid Renewables will also be participating on the call. 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 informational and reconciliations of non-GAAP financial measures to the closest GAAP financial measures. With that said, I will turn the call over to Jim Torgerson.

Thanks, Patricia. And welcome everybody to our call. We actually had a very good quarter for 2016. Net income was $109 million or $0.35 a share, year-to-date it’s $423 million or $1.36 a share. And on a non-GAAP adjusted net income basis, the $109 million stays the same, that’s actually up 44% over 2015’s third quarter. Year-to-date, again on a non-GAAP adjusted net income basis of $1.30, that’s up 45% over the year-to-date 2015. Adjusted EBITDA grew nearly 6% over $1.5 billion. We are executing on our growth strategy now. Capital expenditures are just over $1 billion and they are funded by cash from operations, which totaled about $1.2 billion. In addition, we are executing a Safe Harbor strategy to acquire an additional 2 gigawatts of wind generation by building that through the next few years. So our opportunity there is to buy the equipment, which we are doing right now, we’re executing on that. And then, we will get that build hopefully in the next four years to be able to take advantage of the Safe Harbor provision and then get the full benefit of the production tax credits. We’re also going to be repowering over 350 megawatts of our existing generation, and we’ll talk a little bit about that over putting the money to work with that one as well. On the dividend, the Board has determined that they will maintain the quarterly dividend of $43.2 a share, so the annual dividend $1.728 and that will continue. Now, on Page 7 of the presentation, let me talk a little bit about the earnings. And keep in mind, when you look at the chart you will see that the upper part of the chart just shows the GAAP results. What I want to refer to really is the chart that shows the non-GAAP adjusted net income. And you can see the quarter was up 44%, and the year-to-date, the 9 months, 45%. The reasons for the better performance, we have better wind resources, was actually up about 8%, although that’s still down 5% for the nine months from what we would consider a normal wind resource; the extension of the usual life of the wind assets, that also played into this. And when we look at the adjusted net income and for the renewable business, we’ll be looking at that, and there are some intercompany transactions that occurred. But the renewable business was actually up about 10% when you exclude those intercompany transactions that occurred during 2015. We had improved revenue with the growing rate-base, and particularly the settlement of the New York rate case. Networks’ adjusted net income was up about 14% to $321 million. We had some improved results in gas storage business, and mainly because of the expiration of a contract in 2015. And we continue to focus on our best practices and implementation of those best practices as we keep moving forward. Now, on Page 8 we have our renewable business and the plan is really on track for some additional investments. But let’s look at the ones we had today. We had 744 megawatts that were under construction. We’ve actually added another 66 megawatts of solar on two projects. They will now be completed in 2017-2018 timeframe. The Amazon Wind Farm East project in North Carolina has 208 megawatts. It is under construction. It will be operational by the end of this year. And we have four additional wind turbine projects with the capacity of 536 megawatts in various states that will be operational by the end of next year. Now, looking forward we have additional investment opportunities beyond our current plan. And I think this is very important, because we’re executing on our Safe Harbor strategy that we talked about previously. And we’re going to purchase enough wind turbines to capture the full value of the production tax credits for up to an additional 2,000 megawatts or 2 gigawatts of new wind capacity. Our total pipeline is now up to 6.8 gigawatts, and with 2.1 gigawatts of near-term wind and almost 450 megawatts of solar PV. And keep in mind that under the Safe Harbor strategy by making the investments this year, we will have until the year 2020 to get those operational. We’re also exploring offshore market assessment and particularly in the northeast. The Massachusetts legislation is requesting 1,600 megawatts of offshore wind and we’re working with our partners at Iberdrola, who has actually has 1.3 gigawatts either operating or under construction of offshore wind. So we’re looking at that as a potential. Going to the next page, some recent initiatives we have, and we are executing a repowering strategy for at least 350 megawatts of existing projects. We have the opportunity to retrofit and qualify for the new 100% production tax credits that really benefits our existing wind farms, the new benefits for existing wind farms. It will increase the output by about 20% by retrofitting the components. The economies of this turn out to be very compelling for certain sites, which we’ve identified those sites. And we are going to be offering, what we call a blend and extend product to the customers of the existing fleet. We are finding significant customer interest in this. We also have now announced NIKE as the party that we mentioned last time of signing a new PPA in the Northwest. They have committed to reach - they want to reach 100% renewable energy for their owned and operated facilities by 2025. So we signed a 10-year agreement for renewable energy with them in Oregon, where we will be providing the wind power. The agreement begins in January of 2017, and we can actually serve those from any of three merchant projects we have in the Pacific Northwest. We also, as we’ve reported in the past, executed 100 megawatts of new and extended PPAs in 2016 with traditional utility counterparts. Turning to the Networks business, we are on track with our $6.7 billion of CapEx for - during our forecast period. We have some - the projects we are working on mainly are FERC transmission upgrades, replacements, alternatives, electric and gas distribution that’s mainly for safety and reliability, infrastructure upgrades, ageing infrastructure that need to be replaced, and then customer service automation. Couple of the examples of the utility projects we’ve previously disclosed, one is in New York, it’s the Rochester Reliability Project. And we’re spending about $290 million on that. Then in Connecticut, the Metro-North Railroad Corridor to increase the capacity and reliability of the transmission lines along that railroad corridor and that’s about $175 million. So those investments represent about $6 billion through 2020, which is almost 90% of the plan for Networks. We also have an additional $740 million in the plan for potential transmission growth project. Within that amount, we now have $220 million that are moving forward and are in progress. Specifically, the $108 million for the MEPCO Section 388 rebuild in Maine; and then the $70 million for Lewiston Loop also in Maine, which is expected to be in service by the second quarter of 2018; and then $40 million for three initial projects that are part of New York Transco. We also have the Western New York project, which is a joint proposal with NYPA. It’s going to solve some transmission needs requested by the New York ISO. And this is at new 20-mile 345 KV transmission line, one new substation, and expansion of a couple of more, and reconductoring of number of miles. Now also on the New England clean energy RFP, we were informed yesterday that our two network proposals were not selected. However, we are pretty confident in the value and the merit of this project. And we can even see further opportunities with them, in particular with the new clean RFP in Massachusetts that will be coming about in April of 2017. We have had discussions with some others about firming up the intermittent resource, talking to other hydro producers. This appears to be an activity that the Massachusetts is looking forward to have firm power along with renewable power. So we can firm this up. That seems to be of interest and we’ve already had some discussions with some parties about that. The impact of this on our long-term growth is very much limited. Actually the risk-adjusted amount of this was pretty small. So it’s actually a whole lot smaller than our plan to install the 1.8 million smart-meters in New York. So the impact on our long-term forecast is negligible. So with that, I’m going to go on to the Page 11, which has the regulatory update. The UI rate case is on schedule for a final decision on December 14. When you look at the proposal that UI made for 9.92% ROE, equity 52%, rate base of a little over $1 billion, and then a three-year cumulative rate request of $98 million, what we found out very important is the OCC, the consumer counsel, filing actually was reflective of $27 million increase over the three-year period, smaller rate base and obviously a lower ROE. But you can now see what sort of the bookends would be for this. We have our proposal which we view very strongly and feel it’s a very solid one for the commission to decide and then the OCC’s filing. Those are the only two filings that are typically made in Connecticut, the other parties usually don’t file a case. Other states with NYSEG and RG&E, we have our three-year rate settlement that went into effect in the second quarter. For Central Maine Power, we have the potential for filing in the first-half of 2017. In Connecticut, the two gas utilities, we can’t have rates effective any earlier than January of 2018. So if we determine the rate cases are necessary we would file midyear in 2017. And then Berkshire, we can’t have any rates effective earlier than June of 2018. Now looking at our guidance, earnings were up significantly over 2015. But it’s not meeting our expectations. Therefore, we’re revising our guidance to be from $2.10 to $2.20 to $1.95 to $2.05. Some of the components of that, when we look at particularly the Networks business, certain rate base adjustments, there were some adjustments between the regional network service, the local network service in Maine, which reduced our earnings potential, our earnings there. Bonus depreciation was not fully reflected in 2016. It is going forward. New York was also - we had some adjustments related to the settlement that affected rate base. And then CMP had an annual true-up as well. So there were a number of factors impacting this. Overall, those factors were about $0.03 in 2016 and then the change, the midpoint is about $0.04 that were reflecting. Wind production in the Renewables business, as I said we were off about 5% so far, is what we’re expecting. If we have normal weathers through the fourth quarter, our normal wind production, I should say, we would end up about 4% off. That would mean about a $0.07 impact to earnings. We had already reflected about $0.05 in previous guidance. So the impact there is another $0.02. The useful life adjustments that we had in extending the life of the components of a number of our - of all of our wind farms as a matter of fact, we needed to extend the leases that a lot of these wind farms are on. We’re finding that we’re not getting those all done this year, as we had originally hoped. That will extend into next year. So that’s affecting the earnings there by about $0.04. And we also - when you see, it looks like we’re down about $0.03 is what we’re seeing for renewables. In reality, we had shifted about $0.02 a share from trading that was being done at our gas storage and our operations there, out of gas storage and back into renewables, so that was actually a positive impact of $0.02 a share. So when you look at that renewables was probably understated a little - or overstated a little bit, because it really - we added $0.02 in there. And the gas storage business, which shows-off $0.08 is probably more like $0.06. The low volatility and the fact that we haven’t pulled anything out of storage, because of the warmest winter pretty much on record limited the amount we could then move and operate under. And it diminished what we could - any trading on our existing assets that we would typically be able to do, and so the lack of a margin there prevented us from actually hitting our targets. And we don’t anticipate anything going into the fourth quarter that’s going to dramatically improve that. So we’re making the move to reduce the guidance on that area as well. Having said all that, we are still highly confident of our ability to maintain the 8% to 10% net income CAGR and we’re very happy with that. We have sufficient projects that will allow that to occur. And so we see the growth in our businesses continuing and the 8% to 10% is still very much doable for us. So turning to Page 13, we’re going to be remained focused on our growth objectives, executing our long-term plan to grow our regulated and contracted assets. We have our - capital spending is on track with the plan. We have the Safe Harbor strategy, which is being executed. The repowering plan is being executed right now. The integration is supporting our growth plan. That’s going extremely well. So we’re focusing on identifying and implementing our best practices. And that’s occurring today and will into 2017 as well. Risk mitigation remains a key for us. So we’re actively managing our merchant exposure, trying to turn as much as we can into PPA. And the rate cases, we’re de-risking many of our measures. So we had significant improvement in the year-over-year performance. And as I said, we feel very confident maintaining the 8% to 10% net income compounded annual growth for the period through 2020. And with that, I’m going to turn over to Rich Nicholas to talk a little bit about our financials.

Thank you, Jim. Good morning, everyone. Thanks for joining us today. I’m on Slide 15 of the presentation. And as you see there on the left side of the page, we have the GAAP net income and EPS. And on the right side is the adjusted net income. But the biggest difference on the adjusted side being the inclusion of UIL in the 2015 results, and then excluding the sale of our interest in Iroquois this year and a small write-off associated with the Northeast Direct gas pipeline that occurred in 2016 as well. Also in 2015 there were merger costs that have been adjusted out to get really to an apples-to-apples comparison, demonstrating a 45% growth year-to-date in net income and earnings per share; and a solid growth quarterly as well, 44%, 43% of net income and earnings per share. Moving to Slide 16, as Jim mentioned, there is no adjustments to the third quarter net income, but year-to-date, the items that I mentioned earlier come into play and actually reduces the 2016 income, primarily backing out the sale of our interest in Iroquois. As noted on the slide, the Networks business continues to be the significant contributor to earnings about 75% on a GAAP basis and 79% on an adjusted basis comes from the Network business. Moving to Slide 17, when we consider how we’re doing on an EBITDA basis, overall just under 6% growth on an adjusted year-over-year basis, as you can see Networks about 3%, Renewables a little over 4%. The other, since it’s so small, you get a pretty significant change on a percentage basis, but on a consolidated basis, again, just under 6%, seeing improvements just from the rate settlement in New York, as well as the stronger wind performance, and the roll-off of that underwater contract in the gas business. Turning to Slide 18, a little bit of background information on seasonality and so that you can see what’s in part going to drive our fourth quarter results. When we look at wind, the net capacity factor, the third quarter that we just closed is typically the lowest quarter of the year in terms of wind and coming back up again in the fourth quarter. On the electric distribution side, fourth quarter about the same as the third quarter. Typically second quarter is our weakest there on electric distribution. And on gas delivery, as we enter into the heating season again we’ll see things pick up in the fourth quarter as compared to the third quarter. Obviously, with the cold winters in the Northeast, the first quarter is our strongest on gas delivery. Turning to capital expenditures on Slide 19, significant increase year-over-year, we’re up 55% in deploying our capital into our strategic projects. If we look at the total year for 2016, we would expect to be around $2 billion by the end of the year, so a very strong fourth quarter execution coming. Some of the things in the fourth quarter, Jim mentioned the Safe Harbor strategy and the repowering; those two things alone are about $200 million. And we are also able to complete the turbine contracts for some of our wind projects sooner than expected. And so we would be picking up about $250 million, out of 2017 and into 2016 associated with those projects as well. And we continue on our basic core infrastructure replacement safety reliability projects as well as moving along with the Amazon desert wind construction, which is well underway. Turning to Slide 20, when we look at some of the impacts in 2016, on the Renewables business, we have seen the improvement in wind driving up our capacity factor or load factor by 7%, moving from 28% last year to 30% this year year-to-date. Primarily in the West you see a 2.6 percentage point increase there, up to 30%, and in the South Texas and Texas, where we’ve seen a 4% increase up to 30% as well. And on Slide 21, when we look at the actual gigawatt hours of production, again driven by the West and South Texas were up over 8% in total in terms of actual gigawatt hours produced. Turning to Slide 22, when we look at the combination of prices for our portfolio, our average PPA price is actually up slightly year-over-year, and merchant price is relatively flat up 1%. But we did have some PPAs roll off earlier in the year, and it go into the merchant space. And so if you were to look at our total portfolio result, our average price is actually down a little bit year-over-year. Turning to Slide 23, look at our funding of our capital expenditures. On a consolidated basis on the left hand side of the slide, our free cash flow was $335 million, so well on excess of our capital expenditures, which the CapEx in total was a little over $1 billion, but we do receive funds from customers in certain cases, that’s the contribution in aid of construction. And we transferred some assets into the New York Transco as previously discussed. Networks on the upper right hand side of the slide, free cash flow positive about $67 million and on the bottom half of the slide, again, very strong free cash flow at Renewables, but we will be executing on the Safe Harbor strategy in the fourth quarter, and spending significant capital. So turning to Slide 24, where does that leave us from a balance sheet perspective, continue to have a very strong balance sheet, net leverage 24%, same as it was at yearend 2015, and net debt EBITDA decreasing from 2.5 times to 2.3 times. The net debt in total of $4.7 billion is mostly all at the regulated companies, as we’ve discussed previously. There is a small amount of tax equity financing at Renewables, a little over $200 million. And the UIL holding company debt $450 million is outside the utilities as well. So turning to Slide 25, when we look at kind of a summary of where we are so far this year, solid performance, both third quarter and year-to-date on a consolidated basis, driven by the improved wind production, and the extension of the useful lives of Renewables as well as the New York rate settlement. Underneath the consolidated result, some of the segments there are some intercompany changes year over year that have taken place. In 2015, there was a settlement of an intercompany note in interest payments between Renewables and corporate, and it was positive for Renewables in 2015. So when we look at it in 2016 on a year-over-year basis, it’s going to show a negative result, but if you exclude that Renewables adjusted net income actually increased by 10%. Similarly, the effective tax rate is calculated at a consolidated level and then allocated to the subsidiaries based on their particular circumstances. And so we did see some higher effective taxes at Renewables, but not at the consolidated basis as a whole. Then on the bottom part of the page there, mark to market changes year-to-date, at Renewables there is really no net impact. And at the gas storage business we did see a $0.07 improvement, clearly with the elimination of that contract in 2015 that was underwater. On Slide 26, Jim walked through the guidance changes and at the bottom-half of the page there really some of the things that would influence how we end up for the rest of the year. As you’re aware there are several complaints pending at FERC about the New England transmission ROE. Those are yet to be finalized by FERC and potentially could have a negative impact during the fourth quarter. We’ll see how that plays out in the federal regulatory process. As we discussed wind production, wind prices can vary and we would expect to see more normal wind production in the fourth quarter. And on the gas business, share commodity prices and volatility also have the potential, both positive and negative to affect results. And wind production and wind prices also can be positive and negative. We continue to focus on being efficient and implementing best-practices throughout the year. So in review on Slide 27, how do we compare to 2015 and then on the left part of the page and then on the right part of the page, what things impacted our guidance now; so in Networks, earnings improvements year-over-year, driven mainly by the New York rate case settlements. But as Jim went through, we did have several adjustments to the rate case going forward that were lower than our expectations. On the Renewables side, higher wind production than last year, but still not normal, so not being normal has affected our guidance, as well as not getting all of the leases that we expected to get to extend the useful life, but we will continue to focus on those and look to pick that up in 2017. Small change from the move of power trading, but that’s just intra-segment. And then at the gas business, lower storage spreads, warmest summer in 68 years all affected the trading opportunities and ability to secure margin in the gas business. So consistently 2016 has been an improvement over 2015. We are maintaining the 8% to 10% net income compound average growth rate off of 2014 and that’s off of 2014’s adjusted net income of $538 million. So I look forward to seeing many of you at the EEI conference in early November. And I’ll now hand it back to our operator Danielle for question and answer.

[Operator Instructions] Okay. Looks like our first question comes from Joe Zhou from Avon Capital Advisors. Your line is live.

Hi, good morning or good afternoon.

Good afternoon now, yes.

Yes. So would you provide a timeframe for the 350 megawatt of repowering opportunities? Would that be a near-term or further beyond 2020?

Actually, we’re negotiating currently with the turbine manufacturers. We should have that signed up shortly and we can start construction next year. We have to have it all done by 2020 in order to meet the requirements to get the production tax credits. We would anticipate it would be kind of earlier, but, Frank, do you want to comment on that?

Hi, Jim, thank you. No, I think that it’s - if we have a number of the projects that we could repower over this time. So we’re in discussion with number of current PPA off-take counterparties. And I think that it’s really fair to say it’s somewhere just between now and 2020 is when we could start to do that work…

But it has to be completed…

Complete that work - sorry, have it complete by 2020.

That’s the completed.

Yes.

Okay, got it. And also on the Networks, since you didn’t win the Maine transmission in the New England RFP, are you still comfortable to keep your $740 million of growth CapEx, like growth transmission CapEx? I know that’s probability weighted, but are you going to find other projects to fuel that?

Yes, Joe, right now, we feel pretty good about the number. We will update that probably for the - when we do the yearend results in February. But right now, we feel, okay, because we have a lot of other projects we are looking at. And we will - these will go back in. I mean, we are very optimistic about those two projects. They’re good projects that should get developed. And we’ll be bidding those in, in the Massachusetts RFP. As I said in combination with some hydro providers, it looks like we’re working with them now. So I would expect that that number is good for right now, and we’ll update it in the first quarter. But right now we feel okay with it.

Great. And by the way, when is the - what’s the timing for Massachusetts RFP?

I believe, it’s April 1 of 2017.

April 1, 2017. Thank you very much.

Or at least, let’s say, April of 2017.

Okay, great, great, very helpful. Thank you very much.

Sure, Joe.

The next question comes from Chris Whalley of JPMorgan. Your line is live.

Good morning, guys, this is Chris Turnure.

Hi, Chris.

I wanted to take a look at the cadence of the commodity exposed businesses into the fourth quarter, and then into 2017 and beyond versus your original 8% to 10% overall guidance that you laid out back in February. So you mentioned this summer was particularly warm, some of the trading opportunities were not there. How can we think about that change kind of today versus what you were thinking previously? And then where do you might offset that? And then kind of within that how does the roll-off or the continued roll-off of the expensive transportation contracts play into that as well?

Well, I think when you look at the - our expectation will be more around normal weather, so that we could actually move some gas out of storage, optimize our positions and then take advantage of that. The roll-off of the contracts those will occur over the next couple of years, and so that will be mitigated. But we are not looking to do a lot of trading other than off of our existing assets, and mitigate what we can the positions we have. So with normal weather, I think it will create some volatility that would allow, as you know, trading off your own assets to able to optimize your asset position. And that’s what we are going to be looking to do, so the fact that the winter was extremely warm and nothing was pulled out of storage during the year, are very, very little. It didn’t give us the opportunity to get much done in the summer. It wasn’t a whole lot more helpful, because the way things worked out in the summer time, and we are not looking at doing much more for this winter. So we can’t project that it’s going to get any better at this point for the fourth quarter. So that’s why we are being a little conservative on this.

Okay. And then, other than just weather itself being projected to be normal in your let’s say, fourth quarter and 2017 underlying expectations, is there an improvement and a return to some kind of volatility conditions there?

We would expect with normal weather, you would get return with some volatility that would allow us to then optimize our positions. That’s really all we’re counting on. We are not looking, Chris, at doing anything beyond that with the gas storage activity.

Okay. And then, I guess same question on the power side of the business, which I guess is no longer part of Renewables, but has been moved to the trading and other segment now.

Yes, it was - let me just give you a little background on that. They had separated and this was before our merger, then separated, so that the trading was done out of the gas storage business and some of the other activities were done at Renewables. We just felt it made more sense to consolidate, particularly the electricity trading within the Renewables business. And so, because they can optimize their assets a little better that way. So those are the things we’re looking to do. And I think, going forward we’ll be looking at - obviously their merchant prices that are going to impact us. With where prices are today and as we said it all along our forecast had flat pricing projected in there for the entire period, so a little volatility actually could help a little bit. For the trading, obviously the merchant sale, we kind of like to see prices go up. But we’re not anticipating that in our forecast.

Okay. So flat pricing projected forward off of 2016 year base, as opposed to forward curve rebound.

It’s not the forward curve, but it was really the 2015 prices that we had in our long-term projection, the kind of the end of the year 2015.

And then just to clarify your comments on the different segments right now, at Renewables you have all of the contracted renewable assets and then the power trading operations and then in the gas storage it’s all of the gas-related trading operations.

That is correct.

Okay. And then, I just also wanted to clarify I think on Joe’s question about which transmission projects in New England you know you did not get down.

The two we had in Maine, the one we’re bidding with Emera, which was - so the main reliability within the MCPC project, so those two that we had talked about previously. So the one that came from Northwestern Maine down into New England and then also the one pretty much from the north central part of Maine, those two.

Okay. And then I think, there was a project too that you had bid with Eversource bringing power from the New York State into Eastern Massachusetts.

That one was not selected either.

Okay.

So all three are the ones, the two transmission projects then the renewable project we had, none of those were selected.

Okay. And have you disclosed how much from those projects within your $750 million of risk capital?

No, we have not.

Okay.

They have asked us to keep it confidential. So until we can talk to the states and determine if that still applies, we’ll just keep it confidential for now.

Okay. Thanks, Jim.

Okay.

Our next question comes from the line of Sophie Karp with Guggenheim Securities. Your line is live.

Hi, good afternoon. Thank you for taking my question. Can you help me understand the seasonality in your Networks business a little better? And it seems that based on your guidance you’re expecting the last quarter to be quite a bit higher versus Q1 and Q2. And so how much of that is the result of normal seasonality driven by the gas business versus the timing of adjustments and the true-ups that you mentioned earlier?

The gas business is really driven by heating load. And so as the weather gets colder we’ll finally have some cold weather in the Northeast this week. The fourth quarter is typically better than the second and the third. The first quarter is the big one there. On the electricity business, it’s a little more level across all of New England, Southern New England is driven more by air-conditioning load in the summer. Northern New England is a little more spread evenly through the year, doesn’t get as hot if you will. So we’d all see big seasonality on a consolidated electric distribution business.

I guess my question is, are there any abnormal adjustments that resulted into Q3 this year being that much lower versus Q4? Is this the pattern that we should normally expect going forward?

We did have some rate base adjustments that Jim talked about earlier, but those are embedded now. And I think the charts that we provided on that one slide show really from a production standpoint, the seasonality associated with our businesses that was on Slide 18.

When you look at the gas business in the third quarter, it typically will either breakeven or lose money. So I mean, that will be one of the bigger things that will impact the fourth quarter, because the gas business will be positive in the fourth quarter, not as strong as the first quarter, but it’s a much better quarter for gas.

And one thing also, as you look at the quarter, we had New York rate settlement in May, June of this year. So we are seeing the benefit of that now that will continue to pick up in the quarters as we move forward.

Thank you.

Your next question comes from the line of Joe Zhou, Avon Capital Advisors. Your line is live.

Hey, guys, it’s Andy Levi. How are you doing?

Good, Andy, how are you?

I am all right. Just a quick follow-up, I apologize if you talked about it, right, I was on another call. But so with not wining these three projects and then, I also, I think New York project, I think when it’s called, that wasn’t not in the CapEx. But I know that the selection on that had been delayed as well. When will you refresh your growth rate, because I think you gave like a very robust growth rate 8% to 10% or something? So when will that be refreshed?

Well, we said today that we are confident with 8% to 10% growth rate on earnings through 2020. So we talked about that today. We will refresh the capital when we do the fourth quarter and year-end earnings report, so sometime in February. And so we’ll go from there. But right now, we are pretty confident that the projects that weren’t selected and the two remained, I think we mentioned we will be bidding those into the Massachusetts RFP. Along with, working with some hydro producers that - because they look - Massachusetts is looking at firm power along with renewable energy, so in a combination, it appears, so we’re taking with that.

So what - go ahead, I’m sorry.

Connect New York, we’ll be filing that under what’s called Article 7 in New York, and having that go forward. We haven’t done that yet. We’ve been talking about the project and meeting with a lot of political people and legislative people to talk about the project. And it has some traction. But it’s got a long way to go, that’s why it’s not in our forecast, yet.

Jim, if I could, let me just, because prior question kind of touched on this as well. So as we look at our growth projects, we kind of look at it as a portfolio that we are constantly adjusting to reflect the fact that many of these require certain regulatory approvals. And at times you’re kind of beholding to the process. So specific to Connect New York, this is a project you are familiar with DC underground. We think it’s incredibly attractive, given the fact that anything above ground gets immediate resistance in New York. We were not surprised and it did not meet the sufficiency test. Remember that, preceding that we submitted that project into was an AC proceeding and ultimately the ISO viewed on a fairly narrow scope whether or not you met the criteria or not and based upon the fact that it’s DC, it didn’t meet their criteria. As Jim correctly said, this is a project that we think has great promise. We are working on the Article 7 and all the steps it takes to do that. We fully expect there will be another as a part of the 2016/2017 public policy planning cycle, there will be another opportunity in 2017 to submit this under another form. That will be more conducive to this type of projects. So we are not slowing down at all in terms of the work to getting it prepared for Article 7. And we expect more on this in 2017. As it relates to the clean energy RFP in New England, we are disappointed, obviously, that they weren’t selected. However, we continue to believe that the benefits of those projects relative to others in New England and the cost and the economics of them are such that they are very, very attractive. And as Jim mentioned early in his remarks, one of the things you are seeing in the kind of the new RFP that we file early next year is a strong interest in taking projects predominately in the past just wind projects and firming them with wind. So you have kind of a more holistic…

Hydro.

Okay. I’m sorry, hydro. Thank you, Jim. And so we are looking at that and we fully expect that those will continue. In the interim, given that we have this portfolio of projects we look for other projects that maybe don’t have as much of a need for regulatory approvals to move them forward. So we mentioned MEPCO project and other types of projects like that. There is a FERC rightline [ph] work we’re doing, that we can substitute. Also I will say that for example in that initial guidance last spring, we did not include anything in there with respect to some of the work that needs to get done through the DSIP plan in New York, most notably, full rollout of AMI, which is roughly a $500 million investment. We plan on making that filing with the commission within the next 30 days, hope to have a word on that by let’s say mid next year. So there is a lot of moving parts, but for things don’t work out from the timeline we look to substitute other projects and keep moving these projects that we think have a lot of economic value through the pipeline.

But I think the issue is going to be more as you said at the very least on timing, and I would assume that your growth rate in the earlier years because these projects didn’t come on when you thought and also the whole process whether it’s the New York projects or the New England projects, the process itself to get them approved is taking much longer than expected that your 8% to 10% growth rate in the early years is not achievable, and that its only in the outer years that it’s possibly achievable, isn’t that correct?

Not necessarily, no, because again we’re looking to substitute other projects. Remember, this might just be like let’s say a one year delay or something like that. There are other projects we substituted as it relates again to things in Maine in particular, MEPCO, Brightlline, Lewiston Loop, those types of projects, another one in Brunswick, that we look to substitute that we don’t need the regulatory approvals can be put in place relatively quickly to help offset that as we continue to develop the rest of the pipeline.

So weren’t part of those already incorporated in the projections that you put out there as far as the partial CapEx that you handicapped the waiting?

Some are all probability waited, yes, but in terms of the timing of them that’s where we look to be able to move projects around so as to continue to develop and meet our CapEx targets.

And then my last question was, sorry go ahead…

I was going to say, keep in mind that the RFP projects were not even going to be operational till like 2019 under the original schedule. So we would pick up some AFUDC or some rate base. But most of it was going to be the back-end to begin with. So we’re pretty confident with the 8% to 10% growth. Now that is component growth over the period. And so we never said it was 8% to 10% each year every year, some are higher some are lower. So we’re looking at 8% to 10%. We feel very confident with that and as Bob said, we have projects put in there in substitute and keep as the growth going.

Fair enough. And then one last question just on Rochester, didn’t you get in your rate order some type of, if I remember correctly, transmission upgrade relative to Fitzpatrick closing.

There are two of them. It’s not Fitzpatrick. It’s the potential for Ginna.

Of Ginna, Ginna, I apologize.

There are two large projects that are ongoing. One is called the GRTA. That was the project that will have completed by the end of the first quarter of next year that would allow for the ultimate closure of Ginna, should it happen, okay. And there is another project to further enhance the region called RARP, the Rochester Area Reliability Project. That’s in the early stages and we’re working on that and that was incorporated in the three-year rate plans that we received in June of this year. So two plans both, north of $200 million each, one is going to be completed early next year, the other will go out for the next couple of years. It remains to be seen whether or not obviously Ginna closes with the ZEKS [ph] that were passed, and whatnot. It appears that maybe they’re going to continue to operate, but those projects are on budget, on time and consistent with what we received in the rate cases in June.

I understand that, but my point I guess is that why are those projects necessary if Ginna is going to remain open?

They’re still needed for system reliability in that area, because expected load growth and other issues require that they be there. You still have to have contingencies too, for example, so Ginna stays open, but what if it has a shutdown for a period of time.

Okay, thank you very much.

Andy, one other thing to keep in mind is when the things we’ve been talking about with the renewables, with adding 2,000 megawatts for - under the Safe Harbor provision that should get build in by 2020 and 350 in repowering. Those are going to add to our growth as well. And I think it’s important to remember, it’s not just all of the transmission projects. We have renewable projects that are going to be contribute as well during this time frame. We had projected in our original forecast, only an additional 650 megawatts being built in the 2020 timeframe. Now, we are looking at up to 2,000 megawatts. We don’t have PPAs form yet or anything. We didn’t have PPAs for the 650. But we are feeling pretty good about the 2,000 and we also feel very good about 350 megawatts from repowering. So we have more projects across the board that we can rely on.

Andy, recall that the growth transmission was only about 11% of our total networks CapEx, and the Maine projects were a subset of that. So the overall, it’s not that big of an impact.

Okay. Thank you very much. I might be mistaken. Thank you.

Next question comes from the line of Glen Pruitt from Wells Fargo. Your line is live.

Hi, thanks for taking my question. Just regarding the 2 gigawatts of Safe Harbor equipment, just to clarify so how much of that would be incremental really to what you have for the projection, because you have 744 megawatts of wind by 2018, and a total of $2.8 billion investment in the forecast. Can you just clarify that for me?

Yes, Glenn, we had - in our original forecast, we had the 744 and then another roughly 650, so to make of that 1400 megawatt. Now we are saying we still have the 744, we got another 66 which is solar to bring us up to 800. We think that we are buying equipment to do 2000 megawatts, up to 2000 megawatts beyond the 800 and 350 megawatts at least of repowering. So we are going beyond what we’ve said before of the roughly 1400 megawatt. How much we get done, we’ll look at it. We’re pushing hard, but we wouldn’t be buying equipment for 2000 megawatts, if we didn’t have some confidence to be able to get that put in and get it under contract by 2020.

Okay, great. And the 350 megawatts of repowering is that included in $2.8 billion investment?

No.

Okay. So that’s on top of it.

The $2.8 billion is just for the existing projects under construction right now.

Okay.

I’m Sorry. No, wait a minute. The $2.8 billion was just for the 1400.

Okay, right, right. That makes sense.

Okay.

Okay. And, well, just one separate quick clarification, the rate base adjustments that you mentioned earlier, are those ongoing or one time hit in 2016?

Some are both, Glen. There are some that’s timing projects that have moved out of 2016 into 2017. And others like the clarifications on bonus depreciation would be permanent. So maybe there is $0.02 to $0.03 of share drag resulting from the kind of permanent ones.

Okay, great. Thank you.

Next question comes from the line of Paul Patterson from Glenrock Associates. Your line is live.

Good morning.

Hi, Paul.

Or good afternoon. How are you doing?

Good afternoon. You are right.

So I apologize if I missed on this. But very quickly, what is the long-term - for your long-term guidance, what do you guys have in there for trading? I guess, now you guys have split Renewables from gas and what have you, but what is the number that you guys have in there?

We haven’t put out a separate number for trading. And it’s really trading around the assets to optimize them. We don’t have a big proprietary trading operation, if you will. It’s really to help maintain our positions with our existing assets.

Okay. So - okay then, but in terms of transmission, you guys mentioned there is a risk in an opportunity, the ROE. Could you remind us what you guys have as - what you guys have in your planning with respect to ROE for transmission?

For the FERC transmission, we are taking what we had in the complaint number one, which was 10.57 allowed, then there is some adders on that that would limit the upside with all the adders to 11.74. So it’s kind of a blend to that, but that’s what we used for our long-term projections at this point, because we haven’t had any definitive decisions by FERC subsequent to complaint number one.

Okay. I guess, we’ll probably be getting one in about six months, I guess, right.

Who knows?

Okay. They do seem to run together. Okay.

Sometimes.

We only got two, three and four now. So…

Right. Okay, thanks again. Have a great one.

There are no further questions in queue at this time.

Okay. Well, I want to thank everybody for participating. And if you have further questions, please don’t hesitate to contact our Investor Relations team. And we will be happy to get whatever answers you need. So thanks again, and we will probably see many of you at the Edison Electric Institute Financial Conference. Thanks, Danielle.

…today’s teleconference. You may now disconnect your lines.