We'd like to welcome everyone to the AVANGRID Second Quarter 2016 Earnings Conference Call. I'll 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 second quarter 2016 earnings results. I am Patricia Cosgel, Vice President of Investor and Shareholder Relations. Presenting on the call today are Jim Torgerson, our Chief Executive Officer; and Rich Nicholas, our Chief Financial Officer. Bob Kump, our Chief Executive Officer of Avangrid Networks; 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 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 and Litigation Reform Act of 1995. Significant factors that could cause results to differ from those anticipated are described in our earnings release and filings with the SEC. With that said, I'll turn the call over to Jim Torgerson.

Thanks, Patricia, and good morning, everybody, and welcome to the call. AVANGRID really had a very strong operational financial performance in the second quarter and really its first 6 months as a company. For the second quarter, net income was $102 million or $0.33 a share. Year-to-date, net income was $314 million or $1.01 a share. Our adjusted EBITDA grew about 9% to a little over $1 billion, $1,048,000,000, for the year-to-date. Networks were up about 6% and Renewables up about 13% in EBITDA. Our capital expenditures for the first 6 months, we spent $674 million. That was funded by cash from operations of over $900 million. So we're in good shape on cash being able to fund our capital expenditures. And we also declared -- the board declared its third dividend for AVANGRID at $0.432 a share. It was declared the other day on July 14 and payable October 3. As you know, our dividend plan is to get the payout ratio to the 65% to 75% area. We have -- the board has indicated a floor with the $1.728 a share on an annualized basis, and the yield right about now is a little -- is around 3.8%. And because of the good results we've had, we are affirming our 2016 consolidated earnings per share guidance of $2.10 to $2.20. And now, I'm actually on Page 7 of the presentation. And if you look at the net income, it improved compared to prior periods from year-to-date 2015. And keeping in mind the 2015 results do not include UIL, except for the last 2 weeks, but that was in the -- it's not in the first 6 months at all. So the acquisition of UIL is not in anything for 2015, as required by SEC requirements for our reporting. So you can see we had $314 million compared to $117 million in 2015 year-to-date and $102 million versus $11 million. And the per-share amounts were $0.33 in the quarter versus $0.04, and then $1.01 versus $0.46. The integration of our companies is proceeding on target, as we had anticipated. The year-to-date '16 benefits really from a couple of things: one, better wind resources compared to year-to-date 2015, but still less than what we would call our average; and then, we're also on track for the ongoing implementation of our 5-year strategic plan. Now turning to Page 8. When we look at the results on an adjusted net income basis, and this is adjusted -- this is a non-GAAP financial measure, and it's adjusted for -- to include UIL in 2015, but also the sale of certain investments and the impairment of investment in 2016. So to get it on a comparable basis for ongoing results, you can see that our earnings, our net income grew, on adjusted basis, 45% from $203 million up to $295 million for the year and from $31 million to $100 million for the quarter. And the quarter on an adjusted basis was $0.32 and $0.95 year-to-date. The highlights on this, the -- we improved on the wind production. It was 9% better than the first half of 2015, but that still was about 10% below our -- what we would consider our average. And July, though, has picked up. The wind has picked up, and it's looking a little better now. Another thing that we did was the extension of the useful life of the wind assets. We moved to a component view in the first quarter, and that extended the life from 25 years to about 31 years. Networks adjusted net income reached $79 million in the second quarter versus $43 million in 2015. Again, these are on an adjusted basis. And year-to-date adjusted net income for the regulated activities was $246 million versus $197 million in the 2015 time frame. And really, the improvement in the Networks business was by higher revenues, additional rate base, cost management that we've had in place and then favorable uncollectibles. Renewables adjusted net income was $39 million in the second quarter and $82 million for the first 6 months. Really, in the second quarter of 2015, it appears that -- it appears like a decrease versus that, but there was really a settlement of intercompany transactions that modified the numbers. So actually, we would be up if you tick that out, actually up fairly significantly, as a matter of fact. Turning to Page 9. In Connecticut, we filed an electric rate case, and the 3-year rate filing was made on July 1 for new rates that would go into effect on January 1, 2017. The request was for an ROE of 9.92% on 52% equity. Also talking about a 50-50 earnings sharing after a deadband of plus 20, 30 and 40 basis points in years 1, 2 and 3, respectively. Currently, the ROE for United Illuminating's electric business' distribution is 9.15% on 50% equity, and we do get immediate sharing with customers. We also will be funding a $308 million capital plan through 2019. And really the focus there is on the customer and reliability upgrades to replace mainly aging infrastructure. And the rate base grows from $935 million to a little over $1 billion, $1.032 billion, so about an 11% increase in the rate base over that time frame. Now the schedule would be that with -- the application was filed July 1. We would expect a decision by year-end, with rates going into effect January 1, 2017. And keep in mind, in Connecticut, they really have 6 months. They -- legislatively, it's 5 months to get a case done, 150 days, but they always have another 30 days they add on. So it's a 180-day time frame that you'd be looking at. On Page 10, in terms of the settlement of the New York rate case in the second quarter, that was for all of our companies in New York, NYSEG and RG&E, both gas and electric. We have a 3-year rate plan with rate increases that actually go back to May 1. So you can see some of that reflected in the results just for 2 months of the quarter. Funding for our $2.1 billion capital plan through 2019 and also the recovery of what we had of $260 million of storm costs that were deferred. So we will be recovering those over the time frame. Actually, it's like $40 million a year that we'll recover. So some of the costs are recovered over 5 years and some over 10, but it's about $40 million a year in recovery. The ROE is 9% on 48% equity, but we have a sharing that's 50-50 after 50 basis points above the ROE, so 9.5%, but also on 50% equity. So that raises it a little bit higher. Reconciliation mechanisms are in place on a number of areas for storms, environmental remediation, property taxes, pension and some of the costs related to the REV process in New York. So those all can be recovered under a reconciliation mechanism. The rate settlement also ordered us to meet with the New York PUC staff by August 14 for implementation of an earnings adjustment mechanism, and this would allow a 100 basis point incremental future earnings opportunity. And this is, again, outside the sharing mechanism and allows us to participate in some public policy goals. And the impact, though, is not going to be anticipated until 2018. But 4 of those are mandatory and one is optional. The 4 mandatory ones are the interconnection process, the Clean Energy standard, energy efficiency and system efficiency. And then, customer engagement is optional. And these will all be discussed with the staff and then -- at various times, and then implemented after we come to some conclusion with the staff and then agreed upon with the commission. Page 11. The NYSEG and RG&E filed their 5-year Distribution System Implementation Plan to support REV. And the 5-year filing was made on June 30. And really, what it does is transform us to the smart integrator, where we'd be owning and operating the diverse and intelligent platform that will be utilized for the grid. And the emphasis on the 3 areas is the grid operations, integrated system planning and market enablement. And the cost benefits we had, one, we looked at greater distributed energy resource penetration. And it's really going to require a foundational investment in automated meter reading and automation and control. The smart meters, we are planning to roll out, at least in our proposal, would be to all 1.8 million customers of ours in New York, and that's over a 4-year period once this all gets approved. The AMA -- AMI project costs would be -- and this is capital and operating, about $580 million, and that is incremental to our plan. We do not have this in our strategic plan at all. But it would provide about $710 million of operational and AMI-enabled benefits on a net present value basis when looked at over the 20-year planning horizon. Now the next steps in this would be the stakeholders are going to submit feedback on the DSIP filing. And then there'll be a supplemental filing in November with other utilities and stakeholders on the approaches. And the investments and cost recovery are going to be discussed in future proceedings in front of the New York PSC. Turning to Page 12. For Networks, our utility projects are very much on track. We're focusing, as I said, on resiliency, aging infrastructure, automation. We have some transmission upgrades that are replacements and alternatives. And you can see in the picture, that's the Metro-North line, where we're going to be taking the wires off the catenaries, and I'll talk about that in a little bit. But we also have gas distribution for the pipeline and then some liquefaction we're putting in, in Connecticut. Up in Maine, we have customer service automation for the -- to make our AMI more innovative, flexible -- and provide flexible pricing as well. That'll be primarily in New York. Now the growth projects we have, the New England Clean Energy RFP, as I think you are aware, we submitted 2 confidential bids for transmission. The selection is expected by July 26. We had SunEdison as one of the partners in our proposal. They have come to an agreement with Pattern Energy for the sale of the King Pine Wind project, and that was the bid we had for MREI. And so that should eliminate any concerns the parties might have with SunEdison being there, not that there are too many, to begin with. And we have our other probability-weighted projects, also with the Clean Energy RFP. We had submitted a project from our Renewables business to provide energy coming from wind farms, which would be -- could be -- would be located in New York and then fed into New England. The other opportunities, we have our Connect New York, which is a 1,000-megawatt DC underground transmission line along the New York Thruway, which should help alleviate congestion in the city of New York. That is -- proposal was made at the end of April. And keep in mind, none of that project is in our capital plans at this point. Projects that are in our capital plans are highlighted a little bit on Page 13. They include not only electric but gas distribution and FERC transmission. And as I said, the Metro-North Railroad Corridor, that's been up from $150 million now to $175 million project, which should be implemented between 2016 and 2020. It does increase the capacity and the reliability of the transmission lines along the Metro-North Corridor. And one of the other projects is building 115 kV reconductoring between our Baird Substation and Congress Substation in Bridgeport. So those are -- but the lines on the catenary need to be replaced. Those catenaries are well over 100 years old now, and they cannot support the transmission lines any longer. So we need to remove them and put them on the monopoles along the right of way. We're also putting in a liquefaction replacement for about a $40 million project in Rocky Hill, Connecticut. That'll give us 6 MCF a day of -- 6 million cubic feet a day of liquefier and purification ability. And we use that for our -- to make more economic the peak load servicing we need for our gas distribution company. Then the RG&E, we're putting in a project for the Rochester Area Reliability Project, and this is a $290 million project between 2016 and 2020. It's 23 miles of 150 kV line and then 1.9 miles of 345, plus a substation. We also have some of our growth transmission opportunities, which I want to highlight today. We have the MEPCO project -- and these were in our growth transmission area when we first put this out on Investor Day, back in February. The MEPCO section, it's a rebuild of about a 50-mile, 345 kV. And it's really putting in the -- replacing a lot of the cross-arms on those transmission structures. We've received all of the state approvals. We're going to be presenting this to the ISO New England Planning Committee next month. We've already discussed it with the ISO New England, and they are in agreement with this project that it is definitely needed and needs to be done quickly. The Lewiston Loop. This was originally part of the Maine reliability project, the $1.4 billion project that was completed the end of last year, that got -- now it's being implemented. And this consists of 2 substations, 11 miles of 345, a little over -- about 1.5 miles of 115 kV, and this is about a $70 million project. Then one other, the Western New York, this is -- final selection is expected early in 2017. And this is one where New York ISO completed the sufficiency test already. And so now we're into the cost assessment stage, and hopefully, we'll get a decision on this in the not-too-distant future. Looking at our Renewables business. We have 6.3 gigawatts of a pipeline right now. 1.4, we would anticipate being installed by 2020. The 744 we've talked about before are already under construction, $1.3 billion. We should be operational by the end of this year. And then El Cabo, Tule, Deerfield and Twin Buttes II, which is another 536 megawatts, will be in operation by the end of 2017. All of those projects have long-term PPAs associated with them. We also have the 1.7 gigawatts of wind pipeline that would be providing opportunities for the 2018 to 2020 time frame. And we said we would be building about another 600 megawatts or so in our plan. Obviously, we are striving to do much better than that, but we -- those will be supported by the safe harbor strategy to ensure that we get the full value of the PTCs associated with that. And what I mean by that is we can make investments into wind turbines that we can then spread out to whatever projects are needed and meet the 5% safe harbor guideline in order to make sure that any project we build would have the PTCs at full value. We also have 550 megawatts of solar PV in our pipeline projects for the 2018 to 20. I'm happy to say that the company has approved the investment for 2 solar projects with long-term PPAs of about -- of 66 megawatts. And one will be completed in 2017, the other in 2018. So we're starting again on our way to expanding the solar in our system, which we're very glad to be able to do. We're also, on Page 15, announced that we have -- a global C&I customer has selected AVANGRID to supply them with renewable energy. This will be a 10-year contract. Somewhat variable megawatts, but the -- it'll be equivalent to about 70 megawatts per year, and that increases the amount of PPAs we'll have in 2017 by about 120 basis points. And the contract can be served from any of 3 existing merchant projects in the Northwest. So we've turned some merchant projects into PPAs. And if you look at -- we've actually executed about 100 megawatts of new and extended PPAs already in 2016. So we're moving some of our merchant exposure into PPAs, as we said we would be looking at. Some other milestones on Page 16. We had our Annual Shareholder Meeting and had a quorum of 98%. And the support was 97% of all proposals submitted to shareholders. Probably not overly surprising, since we have 81.5% coming from IBERDROLA, but still, we did have good support from all shareholders. I'm also happy to announce that the board has appointed 2 new independent directors: One is Felipe Calderon, the former President of Mexico, he was president from 2006 to 2012; and Betsy Timm. She's the former President of Bank of America in Maine, and also a consultant today. So we're very happy to have these 2 new independent board members selected for our board. We were also a finalist in 2016, the New York Stock Exchange Governance Award for best governance and risk and compliance in the large cap category. So we're very happy to be one of the finalists. Competition was pretty stiff. Wal-Mart was the winner. But there were other companies like GE, and they were involved in this and as finalist as well. So happy to be in that company. And as I said, the dividend, the board approved a quarterly dividend, payable October 3. And we are -- have a policy to achieve a payout ratio of 65% to 75%, doing that through earnings growth. And we do fully expect to be able to look at raising the dividend sometime during the 5-year strategic planning period we've been talking about. So I want to reiterate, our priority is really in executing on our plan, and we want to focus on our growth objectives. We've said we have an 8% to 10% earnings growth compound annual growth rate through 2020. And this is off of the adjusted net income from 2014, which would include UIL. So it's off of those numbers, which were much better than the 2015 numbers, but we're still -- we're very focused on obtaining that growth objective. Our capital spending is really on track. And we've already committed over $5 billion in investments on the projects I've mentioned today. And of -- and that relates to about $9.6 billion that we have in our 5-year strategic plan for capital spending. The integration plans are in progress. We have -- our best practices have been identified, and now they're being implemented. We still plan on growing our regulated and contracted assets. We had very good performance year-to-date in '16, and that gives us great visibility for the remainder of the year. And we are affirming our 2016 consolidated earnings per share outlook of $2.10 to $2.20 a share. And with that, I'm going to turn it over to Rich Nicholas to run through the financials.

Thank you, Jim. Good morning, everyone. Thanks for joining us this morning. I'm on Slide 19, for those that are following along online. And Slide 19 reflects the as-reported results consistent with the SEC requirements, and so it does not include the combination of UIL, which we'll talk about in a little bit. I do want to note that the second quarter is typically a low quarter for us and our industry due to the seasonality of both electric and gas distribution transmission. We don't have the winter heating. We don't yet have the summer cooling. And also it's typically a low wind resource period during the year. So just to point out, you can't multiply the second quarter times 4 to get to an annualized result. Moving on to Slide 20. Here, you can see both the year-to-date net income and the second quarter and with a total consolidated net income of $102 million for the quarter versus $314 million year-to-date. Again, that's seasonality coming through in the results, but strong results in both Networks, at $79 million or $0.25 a share, and Renewables at $41 million of net income and $0.13 a share. Now on Slide 21. As Jim spoke about earlier, we have the adjusted net income, which includes adding in UIL in 2015, but then also eliminating from 2016 things like our sale of our interest in the Iroquois pipeline that was mentioned in the first quarter. We also had a small write-off of our investment in the Northeast Direct gas pipeline. And so you get to a kind of going forward business view of the world. You could see, even with those adjustments now, significant improvement quarter-over-quarter, over 200%, both in net income and EPS basis, and for year-to-date, 45% increase. And the single largest driver of the improvement there is really on the Networks rate base and revenue as we continue to grow rate base and get the benefit of various rate actions. So moving to Slide 22. Also strong performance from an EBITDA perspective, up approximately 8% to 9%. One change that we've made is noted at the bottom of the page there that we've reclassified government grants and ITC from depreciation and amortization to EBITDA. And this is consistent with other companies in our sector so, again, in order to provide comparability as folks continue to look at the results from AVANGRID. Moving to Slide 23. We've provided some of the major drivers of the change year-over-year on an adjusted EPS basis. And so just to run through them quickly, we talked in the first quarter about the change in the useful lives in Renewables, increasing depreciation lives there, providing a positive net income pickup and $0.02 a share in the second quarter and $0.06 year-to-date. And we continue to work to extend leases on various wind farms, and we'll extend the depreciable lives accordingly. Wind production, as Jim mentioned, up so far this year versus last year, still somewhat below what would be considered normal. And we continue to see the benefit of El Niño abated and better production in the first part of July. Energy management and mark-to-market in the Renewables business, a very positive effect in the second quarter of $0.05 a share. Moving to Networks, as I mentioned, the rate base growth along with the rate actions, very positive for the year, $0.08 in the quarter, $0.13 year-to-date. And we're also seeing somewhat lower uncollectibles compared to last year. As Jim mentioned, we always have a focus on cost management, and so we see a benefit there of about $0.01. And I think that provides a good synopsis of the major drivers of the business year-over-year. So turning to a little more detail on the Renewables business on Slide 24. We have seen an improvement in our load factor, our capacity factor moving from 30% last year up to 32%, really benefiting from the better wind resource in the West and in the South and Texas areas. And on 25, the actual wind production, again, driven by the West and South and Texas area, significant improvement over last year, 9% in total year-to-date. Looking at Slide 26, what's happening on the pricing front. As previously mentioned, we do have various PPAs, agreements, that have escalators in then. So we do see an improvement in our average PPA price, moving basically from $56 to $57, and stabilization in the merchant pricing essentially flat, down just less than 0.5%. Now turning to Slide 27. From a cash flow standpoint, very strong results year-to-date there. You'll notice the CapEx of $590 million for AVANGRID consolidated. And that's a little different than the $674 million mentioned by Jim because, here, we take into account contributions in aid of construction for customers who contribute to certain construction projects as well as the transfer of one of our projects into the New York Transco. So that transfer was $43 million, and the CIAC was $41 million. So on a net basis, very strong cash flow. And the cash from operations plus our sale of the Iroquois interest I mentioned earlier totals $965 million, resulting in free cash flow of $375 million. And our quarterly dividend is about $134 million a quarter, so very good shape there. Both Networks and Renewables had free cash flow year-to-date. And we continue to have strong credit metrics, with our net debt-to-total capitalization in the 23%, 24% range. So given the strong results to date, we are affirming our consolidated outlook. I would note that we've made a shift between Networks and others. In the first quarter, the results from the Iroquois sale were inadvertently included in Networks. They should have been in other, and they were, in fact, booked in other. So continue to look forward to the rest of the year. And with that, I'll hand it back to our operator, Danielle, for the question-and-answer period.

[Operator Instructions] Looks like our first question is from the line of Andy Levi from Avon Capital.

Just 2 quick questions. Is there any guidance that you guys can give us, just as far as the Networks business, on the tax rate we should use? I mean, I know each individual utility has a tax rate, but like when we kind of consolidate it together, is there some type of tax benefit when you kind of bring it over to parent? That -- I'm just curious kind of what we should be using since -- we've kind of been wrestling with that.

Sure. Andy, this is Rich. On a consolidated basis, typically, you look at the statutory rate, and then we get a benefit from the PTCs. And so we're kind of in that 33% range. Networks is typically closer to the statutory rate, but there are some things in various states that are flow-through versus normalized, but not too far off from statutory.

I guess maybe I should have asked it a different way now since I heard your answer. So the $1.56 to $1.62, that's -- is that based on kind of the statutory rate? Or that's like kind of when you consolidate it into AVANGRID, that's what it ends up coming out to? Do you -- does that make sense, the way I'm asking it?

Yes. Yes, Networks would be closer to the statutory.

Got it. Okay, that was what we were wondering. And I think that was the only question we have, right? Because the PPA price, you kind of gave us the change there, and that was kind of my other question. And when you got to the slide, I saw that, so I'm good.

The next question comes from the line of Chris Turnure from JPMorgan.

Could you give us some more detail and next steps on the New York utility Earnings Adjustment Mechanisms? It looks like you're going to have discussions on that next month, and that does give you some upside opportunity. But kind of what are the next steps? How should we think about just how that works in general? Capital, potential, size, et cetera.

Yes, the next step is there's going to be a meeting with the staff. There has to be one by, I think it's August 14, to open up discussions. But it's going to take until probably -- nothing is going to go into place until probably 2018. And you saw the 5 areas that are -- have potential. So -- and those will each be phased in over -- at different points in time. Most of them -- a couple by the end of the year, then a couple into 2017. So I don't know, Bob, do you want to add anything to that?

Yes -- no, Jim, that's exactly right. We'll be negotiating and working with staff on developing these. Some of the metrics that we'll use to measure us haven't even been developed yet. Many of them haven't and won't be probably until the latter part of this year into next year. So I'd say there's a chance that maybe a small portion of this could be effective in 2017, but we're really looking at 2018 for full implementation.

Okay. And should we look at these as simply incremental capital opportunities that would earn 100 basis points of excess ROE versus your current settled/authorized amount? Or is the mechanism different?

Yes, it's not -- right. It's not capital. It's really how we perform on certain metrics. And the calculation of 100 basis points would be completely separate from the earnings sharing methodology, which we talked about it, basically 9.5% and 50-50 share. So this 100 basis points would be an aside from however we do it in the rest of the business.

Yes, we really want to look at it as additional earnings opportunities and how they get structured. So that's going to be the key in how that gets worked out with the staff and the commission.

Okay. So basically it's like a bonus payment. If you hit these those metrics, you would get that reward as a result of that?

Yes.

Correct.

For some of -- yes. But look, like Bob said, a lot of it still has to be worked out, but yes, that's basically it, Chris.

And you mentioned kind of 2018 might be the first year we actually see a little bit of an impact from this. Is there any of this baked into your current 5-year plan?

No. No.

No.

Okay, great. And then, my next question is on the new kind of C&I customer. It sounds like a pretty straightforward retail contract there that would alleviate some of your supply risk because you have multiple assets that would underlie that. But could you kind of speak to that a little bit and indicate if there is future potential opportunities for you guys to mitigate that merchant risk that you still have through other similar contracts? And kind of how much leeway do you have there in terms of your commitment to the customer on price and volume versus the assets that are backing that? And maybe if you could tell us, too, the duration of that contract.

Yes, the contract's for 10 years. And the benefit of it is that we have a number of merchant sites out in the Pacific Northwest that we can now utilize to fulfill that contract. Obviously, as we move things along -- and like I said, we extended or renewed up to like 100 megawatts, including the 70 this year already. So we're out constantly looking at ways to turn what we have as merchant into PPAs. And -- but it has to be the right situation where there's a customer who wants a longer-term arrangement. So -- but we constantly look at that, and I think there's -- we'll continue to keep working on opportunities as they come around in all the areas where we have merchant capacity. I don't know, Frank, anything you want to add?

Yes, Jim. The one thing I would say is that this is a market segment that we are excited about, because, of course, we do have some merchant capacity. But also, it's a customer segment that is looking for not only green energy, but energies for services supply. And so we're able to do a value-add, given our capabilities, to manage it off of our fleet and basically manage their supply need. So it's a little bit, I'd say, more unique. There's a small group of companies that can probably do that. It's just a segment we really like. And it's something that we can use our existing fleet and take the benefit to hedging out some merchant capacity and earn a margin on it. So -- but otherwise, you've covered it. Thanks.

The next question comes from the line of Paul Patterson from Glenrock Associates.

Just to sort of follow-up on this hedging stuff. The $0.05 associated with mark-to-market and energy management, could you break that out a little bit more, elaborate a little bit more on it?

Sure. As we look at all of our hedges and determine when there's sufficient price discovery on a liquid market to set up the pricing around, in this quarter, we did have some that moved into that category. And so we actually booked the result of the -- a couple of hedges there, moving into that price discovery realm. And that's the majority of that pickup there.

What does that do to -- I mean, how should we think, just in general, of the mark-to-market impact? When you look at the cash flow statement, it looks like you guys have losses. In other words, it's a positive cash flow impact vis-à-vis net income. How should we think about it? Just if you could just elaborate a little bit more on it. Because I believe, in the first quarter, you guys indicated that you were positive on mark-to-market. Could you just give me a little bit more feeling for how that should work going forward?

Sure. Frank, could you elaborate on that a little bit for us, please?

Well, sure. We have some hedges on our wind portfolio that don't -- that as -- that have to be marked to market; they don't qualify for hedge accounting. So as you have price movements, you simply have movements in the marked period. The period for which you have liquid pricing, you mark them to market. We are positive for the year, and we will continue to have mark-to-market movements. But I mean, they're pure -- they're not cash flow, they're pure mark, and you'll realize them when the hedge is settled over time.

Okay. And so the fact that you guys have monetized some of them or you've locked in some of them, I guess...

No, no, no. They just -- we have not monetized them.

No, no. No we didn't.

Sorry. Just to be clear, this is just normal movement in mark-to-market. The -- and...

Okay, so price discovery and what-have-you.

And as we move forward in time, we bring more. And so you happen to have some hedges that are deeper in the money. You have -- as you move the liquid period forward, you're just -- you're bringing in some more in the money hedge there, is all that's happening there.

Should we expect some of them to reverse as you begin to -- as the hedges come to -- as the hedges fall off and what-have-you? I mean, how should we think about -- I mean, it's -- I don't want to get too deep in the weeds here, but when we're thinking about mark-to-market and your earnings, how should we think about the fact that some of this price volatility, which is giving you a benefit but it's really based on a hedge, is going to work out over time? Do you follow me?

Yes, I do. And I think, just to be clear, and I don't have the specifics in front of me but Rich might, which is that part of the reason you have that movement is that, last year, there were some losses on the mark-to-market that are offset this year by some gains on mark-to-market. So you're always going to have some up and down during -- especially quarter-over-quarter, you're going to have some volatility in that mark-to-market. So yes, they will roll off, and you will have -- but then you'll realize the actual income as the hedge settles.

All right. And looking into the future, it will depend on the movement of both power and gas prices to -- it could continue to provide increasing benefits, or if prices move the other way, it could be a negative.

We just got a minute [ph] , Paul.

The reason there was a gain is because the prices on the underlying energy were lower. I mean, the hedged item was lower.

Okay. I'll follow up with you guys afterwards. I don't want to get too far afield on this topic. I know how it can get complicated. Just on Connect New York and the AMI, what would the size of Connect New York potentially be? I'm sorry if I missed that. And my understanding is that's not in your plan right now. Is that right?

That's correct. It's not in the plan. We haven't said anything about what the dollar amount is. It's 1,000 megawatts of DC underground. It's been a confidential RFP response that we provided, and so we really haven't put out a number on that yet.

When would we -- might see a decision on it?

I think it's like early 2017 is what, I think, we're hoping for.

And then, with respect to AMI, you mentioned $580 million, and I believe this is also not in the plan, but that's including capital and operating costs. What's the capital number? And how should we think about what the potential -- because I think there is some support here in New York for this stuff. What's the potential capital or rate base benefit we might be seeing with respect to AMI if it does come to fruition?

I don't think we've broken that out yet publicly, I should say.

Your next question comes from the line of Andrew Weisel from Macquarie Capital.

My first question on the updated guidance, I understand the shift relative to the Iroquois gain in the first quarter. My question is, should we think of the Networks guidance as being a good kind of basis on which you would grow in the years future, whereas that other segment, we would strip out the $0.06 gain and think of that as the run rate?

It -- certainly, stripping out the $0.06 off of other. But recall that the gas storage business is in the other category. That also can have some mark-to-market variances on a -- in a given period.

But then also, with the Networks, keep in mind that we have -- the rate case settlement in New York is from May 1 going forward. So in the future, you're going to have the full benefit of the rate case settlements that -- for the years going forward. So you've got to factor that in.

Right, understood. But in other words, the updated guidance for Networks does not have any onetimers in there?

That's correct.

Yes, that's true.

Okay, great. My next question is the 100 megawatts of new and extended PPAs. Should we assume that those are priced in the ballpark of the realized merchant prices in the second quarter, around $35? And maybe bigger picture, how would you philosophically think about taking a lower PPA price, something closer to merchant, in exchange for extending the contracts?

I think they're slightly above -- they're somewhat above the merchant amounts. But we obviously haven't and won't disclose prices. And going forward, we would look at signing PPAs, assuming we can do somewhat better than the merchant price. Because if we're going to take on the risk of supplying for an extended period of time, we want to make sure we're getting compensated for that risk. So you're not going to sell it at a merchant price when -- for a long period of time. But I don't know, Frank, do you have anything you want to add to that?

No, I agree. And it's -- they're -- you'll get better pricing than the merchant. And of course, it depends on the segment of the United States that we're extending it in, but definitely, we're firming it up because we can get a better price. And we look at our forward view and we say, is this value added for the -- if you will, the hedge that we're getting? And we're very happy with these PPAs, which is consistent with what we said we'd be doing, which is looking to different segments to see where we could hedge out merchant capacity where it made economic sense. And these do make economic sense.

So does that implicitly mean that you think that the forward curve is too low, or that there's more upside potential than downside risk to the curve?

No, simply that the market will pay for the certainty of the price on a contract. I mean, a lot of customers want price certainty, so...

Okay, great. Then my last question, just on seasonality. Obviously, it's a fairly new company in its current form. How did the second quarter compare to your internal plans? My estimate was way off, as were most of my peers and investors. How should we think about the second quarter versus your internal plans? And any help you could give us to think about seasonality going forward, particularly 3Q versus 4Q, would be very helpful.

Well, I think if you look at our full year guidance and the fact that we didn't change it, our first half of the year is performing well. And third quarter, again, you've got a mix. Obviously, there's very little natural gas distribution sales, but you do have summer cooling at the electric companies. And second half tends to be better from a wind resource basis.

So I think when you get into the fourth quarter, and obviously, the gas business will start picking up in the, really, latter part of November and December. Electric, you get longer nights, less -- so you have more lighting opportunities, but really, for electricity, it's the third quarter that's usually the best. Second -- fourth quarter is probably okay. Second quarter is usually the low.

So with all those puts and takes, should the third quarter and fourth quarters look similar?

Yes, weather could have a big impact.

Yes, it's hard to say. They're going to be a little -- they'll always be a little different. I just -- fourth quarter usually would be a little less than the third quarter, I'd have to expect. But again, it depends on weather, like Rich said.

The next question comes from the line of Rodney Rebello [ph], Cannon Asset.

It's actually Scott Senchak. Just a question. So on the year so far, what was the total mark-to-market for both the wind business, and then also the gas business that you guys mentioned?

We haven't put those numbers out yet. There'll be some additional details in the 10-Q, but typically, we don't break out the mark-to-market on the gas.

Okay. But on the wind side, how much was it?

I don't have that figure handy.

You guys mentioned $0.05 cents earlier, is that right?

That included what I would call energy management...

Oh, got you. Got you. Okay. So the $0.05, and that's not quarter-over-quarter or year-over-year, that's an absolute number?

I'm sorry, Scott. What was that?

Is it -- sorry. The $0.05 you guys talked about for mark-to-market, is that year-over-year or is that just this year so far?

No, that's year-over-year.

That's year-over-year. And so you haven't given us the absolute number, is what you're saying?

Correct.

Okay. And then is there anything contemplated in guidance for mark-to-market on the year?

Basically, what's happened so far.

So you have put what's happened so far is now included in your guidance. Got you.

Next question comes from the line of Andy Levi, Avon Capital.

I just have a follow-up to Scott and Paul's questions. I'm just, I guess, a little confused, which is not new for me because I seem to get confused a lot. But just on the mark-to-market, so mark-to-market is part of your guidance in general, is that kind of what you're saying?

Well, when you look at our results to date and our full year guidance, our ability -- well, not our ability, but maintaining that full year guidance also reflects what we've done so far this year. And so what we've done so far this year included some mark-to-market.

Earnings.

Right.

And that's a positive for the year? Is that -- mark-to-market is supposed be positive for the year, but you haven't quantified publicly how much that is in your guidance?

Right.

Okay. Is that typical? Because I don't really remember a lot of companies using mark-to-market as part of their overall adjusted earnings guidance.

Yes, we're not forecasting mark-to-market. What I was saying was that the actual results year-to-date includes the mark-to-market impacts. And so that's already done and behind us, and when we look at the second half of the year, hitting those guidance targets include the first half actual results.

Okay. But when you gave the original guidance at Analyst Day, obviously, you revised it because of, let's say, depreciation. Did that contemplate any type of mark-to-market?

No, no.

Okay, but now it's part of the guidance?

Part of the actuals.

All right. And it's a positive?

Right.

Next question comes from the line of Leon Dubov from Luminus.

Yes, can you hear me?

Yes.

Sorry, I might have missed this earlier. Did you guys talk about the tax rate that you saw for the quarter? It seemed fairly high to me with $172 million of tax expense on $274 million of income. Can you just comment on that and explain how that's different from statutory?

Yes, when you look at just the tax line, there were some adjustments there coming out of the New York rate case for unfunded future taxes. If you take -- and there's an offset to that up in the revenue line. So there's no net bottom line impact. So if you take that out, it's about a 33% effective tax rate.

Okay. So it's just a onetime adjustment this quarter, and it doesn't have a net income effect?

That's right.

[Operator Instructions] There are no further questions in queue.

Okay. Well, thank you, Danielle, and thanks, everybody, for participating today. We look forward to seeing you all in the future. And if you have any other questions, please don't hesitate to contact our IR team, and they'll be happy to get with you. So thanks again, and have a good day.

This concludes today's teleconference. You may now disconnect your lines.