Avangrid Inc (AGR) 2016 Q2 法說會逐字稿

We would like to welcome everyone to the Avangrid second-quarter 2016 earnings conference 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 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 US Private Securities 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 will 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 and financial performance in the second quarter and really its first six months as a Company. For the second quarter, net income was $102 million or $0.33 a share. Year to date, the net income was $314 million or $1.01 a share. Our adjusted EBITDA grew about 9% to a little over $1 billion -- $1.48 billion for the year to date. Networks were up about 6% and Renewables up about 13% in EBITDA.

Our capital expenditures for the first six months, we spent $674 million. That was funded by cash from operations of over $900 million. So we are in good shape on cash being able to fund our capital expenditures.

We also declare -- the board declared its third dividend for Avangrid at $0.432 a share. That 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 haven't -- the board has indicated a floor with the $1.728 a share on an annualized basis, and the yield right about now is around 3.8%. And because of the good results we have had, we are affirming our 2016 consolidated earnings per share guidance of $2.10 to $2.20.

And now, I am 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 two weeks. But that was in the -- it is not in the first six months at all. So the acquisition of UIL is not in anything for 2015 as required by SEC requirements for 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 2016 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 are also on track for the ongoing implementation of our five-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 is adjusted 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 an 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, we improved on the wind production. It was 9% better than the first half of 2015, but that still was about 10% below what we would consider our average. And July, though, has picked up -- the wind has picked up and it is 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 extends 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 timeframe. And really the improvement in the Networks business was by higher revenues, additional rate base, cost management that we have had in place, and then favorable on collectibles.

Renewables' adjusted net income was $39 million in the second quarter and $82 million for the first six months. Really in the second quarter of 2015, 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 took 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 three-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 dead band of plus 20, 30 and 40 basis points in years one, two and three, 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 -- $1.32 billion. So about an 11% increase in the rate base over that timeframe.

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 six months. Legislatively, it is five months to get a case done -- 150 days, but they always have another 30 days that they add on. So it is a 180-day timeframe that you would be looking at.

On page 10, turning to 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 three-year rate plan with rate increases that actually go back to May 1 so you can see some of that reflected in the results for two months of the quarter.

Funding for a $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 timeframe.

Actually, it is like $40 million a year that we recover. So some of the costs are recovered in five years and some will be 10. But it is about $40 million a year in recovery.

The ROE is 9% on 48% equity, but we have a sharing that is 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 PSC staff by August 14 for implementation of an earnings adjustment mechanism, and this would allow 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 anticipate it until 2018. But four of those are mandatory; one is optional. The four 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 in NYSEG and RG&E filed their five-year distribution system implementation plan to support REV. And the five-year filing was made on June 30, and really what it does is transform us to the smart integrator where we would be owning and operating the diverse and intelligent platform that will be utilized for the grid. And the emphasis on the three areas is the grid operations, the integrated system planning, and market enablement, and the cost benefits we had. One, we looked at greater distributed engine resource penetration, and we are really going to require a foundational investment in automated meter reading and automation and control. The smart meters, we are planning to roll out and, at least in our proposal, would be to all 1.8 million customers of ours in New York, and that is over a four-year period, once this all gets approved. The AMI project costs would be -- and this is capital and offering -- 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 will be a supplemental filing in November with other utilities and stakeholders on the approaches. And the investments in 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 are 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 is the Metro-North line where we are going to be taking the wires off the catenaries. And I will talk about that in a little bit.

But we also have gas distribution for the pipeline and then some liquefaction we are putting in in Connecticut.

Up in Maine, we have customer service automation for the -- to make REMI more innovative, flexible and provide flexible pricing as well. That will 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 two confidential bids for transmission, and the selection is expected by July 26. We had -- SunEdison Inc. is 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 were 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 located in New York and then fed into New England.

The other opportunities we have are Connect New York, which is the 1000-megawatt DC underground transmission line along the New York Thruway, which would help alleviate congestion in the city of New York. That 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 has been upped 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 a 115-KV re-conduct ring between our Baird substation and Congress substation in Bridgeport. 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 move them and put them on the monopoles along the right-of-way.

We are also putting in a liquefaction replacement for about a $40 million project in Rocky Hill, Connecticut. That will give us 6 mcf a day -- 6 million cubic feet a day of liquifier and purification ability, and we use that to make more economic the peak load servicing we need for our gas distribution company.

Then, RG&E, we are putting in a project for the Rochester reliability project, and this is a $290 million project between 2016 and 2020. It is 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 is a rebuild of about a 50-mile, 345 kV. And it is really putting in the -- replacing a lot of the cross arms on the transmission structures. We have received all the state approvals. We're going to be presenting this to the ISO New England planning committee next month. We have 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 at the end of last year that got now it is being implemented, and this consists of two substations, 11 miles of 345, and a little over about a mile and a half, 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 this efficiency test already. And so now we're into the cost assessment stage, and hopefully we will get a decision on this in the not-too-distant future.

Looking at our renewal business, we have 6.3 gigawatts of a pipeline right now. 1.4 gigawatts we would anticipate being installed by 2020. The 744, we have talked about before, are already under construction at $1.3 billion. The Amazon Wind Farm East should be operational by the end of this year, and then Alcova, [Tulay], Deerfield, and Twin Buttes, too, 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 timeframe, 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 those would 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 guidelines in order to make sure that any project we built would have the PTCs at full value.

We also have 550 megawatts of solar PV in our pipeline projects for 2018 to 2020. Happy to say that the Company has approved the investment for two solar projects with long-term PPAs of about 66 megawatts, and one will be completed in 2017, the other in 2018.

So we are starting to get on our way to expanding the solar in our system, which we are very glad to be able to do.

We, also, on page 15, announced that we have a global C&I customer has selected the online grid to supply them with renewable energy. This will be a 10-year contract, somewhat variable in megawatts, but it will be equivalent to about 70 megawatts per year. And that increases the amount of PPAs we will have in 2017 by about 120 basis points, and the contract can be served from any of three existing merchant projects in the Northwest.

So we have turned some merchant projects into PVs.

And if you look at -- we have actually executed about 100 megawatts of new and extended PPAs already in 2016. So we are moving some of our merchants' exposure into PPAs, as we said we would be looking at.

Some other milestones on page 16. We had our annual shareholder meeting, and we 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 am also happy to announce that the board has appointed two new independent directors. One is Felipe Calderon, the former President of Mexico. He was President from 2006 to 2012. And Betsy Timm. She is the former President of Bank of America in Maine and also a consultant today. So we are very happy to have these two 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 in risk and compliance in a large cap category. So we're very happy to be one of the finalists. The competition was pretty stiff. Walmart was the winner. But there were other companies like GE and they were involved in this and was a finalist as well. So happy to be in that company.

And, as I said, the dividend, the board approved the quarterly dividend payable October 3, and we have a policy to achieve a payer ratio of 65% to 75%, doing that is earnings growth, and we do fully expect to be able to look at raising the dividend sometime during the five-year strategic planning period we have been talking about.

So I want to reiterate our priorities, really, in executing on our plan, and we want to focus on our growth objectives. We have said that we have an 8% to 10% earnings growth 8% compound annual growth rate through 2020, and this is off of the adjusted net income from 2014, which would include UIL. So it is off of those numbers, which were much better than 2015 numbers, but we are very focused on attaining that growth objective.

Our capital spending is really on track, and we have already committed over $5 billion in investments on the projects I have mentioned today. And that relates to about $9.6 billion that we have in our five-year strategic plan for capital spending. The integration plans are in progress. We have -- our best practices have been identified. Now they are being implemented. We still plan on growing our regulated and contracted assets. We had very good performance year to date in 2016, 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 am 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.

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 accommodation of UIL, which we will 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 is typically a low wind resource during the year.

So just to point out, you can 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 total consolidated net income of $102 million for the quarter versus $314 million year to date, again that seasonality coming through in the results, but strong results in both Networks at $79 million or $0.25 a share and Renewables of $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 to sort of get to a kind of going forward business view of the world. And you can see, even with those adjustments now, significant improvement quarter over quarter, over 200% on both the net income and EPS faces, and for year-to-date 45% increase. And the single largest driver of the improvement there is really in the Networks' great 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 have made is noted at the bottom of the page there, that we have reclassified the 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 have provided some of the major drivers of the change year over year on an adjusted EPS basis. And 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 pick up 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 windfarms, and we will 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 Nino abating and better production in the first part of July.

Energy management, 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-based growth, along with the rate actions, very positive for the year, $0.08 in the quarter, $0.13 year to date. Then we're also seeing somewhat lower on collectibles 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 that, I think, 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%, clearly 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 is happening on the pricing front? As previously mentioned, we do have various PPAs agreements that have escalators in them. 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 0.05%.

Now turning to slide 27, from a cash flow standpoint, very strong results year to date there. You will notice the CapEx of $590 million for Avangrid consolidated, and that is 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 a transfer of one of our projects into the New York Transco. So that transfer was $43 million, and the [sea act] 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 have 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, but I would note that we 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 will hand it back to our operator, Danielle, for the question and answer period.

(Operator Instructions) Andy Levi, Avon Capital.

I never get my first question, so that is kind of weird. Two quick questions. Is there any guidance that you 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 when we kind of consolidate it together, is there some type of tax benefit when you bring it over to parent? I am just curious what we should be using because we have kind of been wrestling with that.

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 are 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 I should have asked it a different way since I heard your answer. So the $1.56 to $1.62, that is -- is that based on the statutory rate, or that is kind of when you consolidate it into Avangrid, that is what it ends up coming out to? Does that make sense the way I am asking it?

Yes. Networks would be closer to the statutory.

Got it. Okay. That is what we were wondering. And I think that was the only question we have, right, because the PPA price you gave us the change there, and that was my other question. And when you got to the slide, I saw that. So I am good. Thank you very much.

Chris Turnure, 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 what are the next steps? How should we think about just how that works in general, capital potential, size, et cetera?

The next step is there is going to be a meeting with the staff. There has to be one by, I think, it is August 14 to open up discussions. But it is going to take until probably -- nothing is going to go into place until probably 2018, and you saw the five areas that 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 and then a couple in the 2017. So I don't know, Bob, do you want to add anything to that?

Yes. No, Jim. That is exactly right. We will be negotiating, working with staff on developing these. Some of the metrics that we will use to measure us haven't even been developed yet, and many of them haven't and won't be probably until latter part of this year into next year.

So I would say there is a chance that maybe a small portion of this could be effective in 2017, but we are really looking at 2018 for full implementation.

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?

It is not capital. It is really how we perform on certain metrics, and the calculation of 100 basis points would be completely separate from the earnings sharing methodologies we talked about, at basically time 9.5% 50/50 shares. So this 100 basis points would be an aside from however we do in the rest of the business.

If you really want to look at it, there's additional earnings opportunities on how they get structured. So that is going to be the key and how that gets worked out with the staff and the commission.

Okay. So, basically, it is like a bonus payment. If you hit these metrics, you would get that reward as a result.

Yes. Correct. For some of them, yes. Like Bob said, a lot of it still has to be worked out, but yes. That is basically it, Chris.

Okay. And you mentioned 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 five-year plan?

No.

No.

Okay. Great. And then, my next question is on the new 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 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 back? And maybe if you could tell us, too, the duration of that contract.

Yes. The contract is 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 are constantly looking at ways to turn what we have as merchant into PPAs, but it has to be the right situation where there is a customer who wants a longer-term arrangement. But we constantly look at that, and I think we 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 is a customer segment that is looking for not only green energy but energy services supply. And so we are able to do a value add given our capabilities to manage it off of our fleet and basically manage their supply needs. So it is a little bit, I would say, more unique. There is a small group of companies that could probably do that. It is just a segment we really like and that we can use our existing fleet and take the benefit to hedging out some merchant capacity and earn a margin on it. But, otherwise, you covered it. Thanks.

Paul Patterson, 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 that.

Sure. As we look at all of our hedges and determine when there is sufficient price discovery and 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 is 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 is a positive cash flow impact vis-a-vis net income. How should we think about it? If you could just elaborate a little bit more on that. 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 have to be mark-to-market. They don't qualify for hedging accounting. So, as you have in price movements, you simply have movements in the marked period. There is a 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 they are pure -- they are not cash flow. They are pure mark, and you will realize them when hedges settle over time.

Okay. And so the fact that you guys have monetized some of them or you have locked in some of them like --

No, no. We have not monetized them. Sorry. Just to be clear, this is just normal movement in mark to market. (multiple speakers).

Okay. The prices (multiple speakers).

Move forward in time, we bring more, and so you happen to have some hedges that are deeper in the money. As you move the liquid period forward, you are just -- you are bringing in some more in the money hedge there is all that is happening there.

Should we expect some of them to reverse as you begin to -- as the hedges fall off and what have you? I mean, how should we think about -- I don't want to get too deep in the weeds here, but when we are thinking about mark to market and to earnings, how should we think about the fact that some of this price volatility, which is giving you benefit, but is 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 -- 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 the -- especially quarter over quarter, you're going to have some volatility in that mark-to-market. So yes, they will roll off, but then you will realize the actual income as the hedge settles.

And looking into the future will depend on the movement of both power and gas prices that are due. It could continue to provide increasing benefits, or the prices move the other way, it could be a negative.

(multiple speakers)

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

I will 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. My understanding is that is not in your plan right now. Is that right?

That is correct. It is not in the plan. We haven't said anything about what the dollar amount is. It is 1000 megawatts of DC underground. It has been a confidential RFP response that we provide, 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 is like early 2017, I think we are hoping for.

And then, with respect to AMI, you mentioned $580 million -- and I believe this is also not in the plan, but that is including capital and operating costs? What is 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 is 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 have broken that out yet publicly, I should say.

Okay. Thanks so much.

Andrew Weisel, 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?

Certainly stripping out the $0.06 out of other, what we call, the gas storage business is in the other category. That also can have some mark-to-market variances in a given period.

But 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 for the years going forward. So you have got to factor that in.

Right. Understood. But, in other words, the updated guidance for Networks does not have any one-timers in there?

That's correct.

Yes. that's true.

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 are slightly above -- they are somewhat above the merchant amounts, but we obviously haven't disclosed 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 are getting compensated for that risk. So you are not going to sell it at a merchant price for a long period of time.

I don't know, Frank, do you have anything you want to add to that?

No, I agree, and you will get better pricing than the merchant. And, of course, it depends on the segment of the United States that we are extending it in, but definitely, we are 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 are getting, and we are very happy with these PPAs, which is consistent with what we said we would be doing, which is looking into 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 is more upside potential than downside risk to the curve?

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

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

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 have got a mix. Obviously, there is 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 as 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 so you have more lighting opportunities, but really, for electricity, it is the third quarter that is usually the best. 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?

Weather can have a big impact.

Yes, it is hard to say. They are going to be a little -- they will always be a little different. Fourth quarter usually would be a little less than the third quarter, you would have to expect. But again, it depends on weather, like Rich said.

Rodney Rebello, Cannon Asset.

It is actually Scott Senchak. How are you? 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 will 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?

Don't have that figure handy.

You guys mentioned $0.05 earlier. Is that right?

Yes. That included what I would call energy management.

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

I'm sorry, Scott. What was that?

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

No, that is year over year.

That is year over year. And so you haven't given us the absolute number is what you are saying?

Correct.

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

Basically, what has happened so far.

Okay. So you have put what has happened so far is now included in your guidance. Got you. Okay. Thank you very much.

Andy Levi, Avon Capital.

I just have a follow-up to Scott and Paul's questions. I am just a little confused, which is not new for me. 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 are 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 have done so far this year. And so what we have done so far this year included some mark-to-market.

Earnings?

Right.

And that is a positive for the year? Is the mark-to-market supposed to be positive for the year?

Yes.

But you haven't quantified publicly how much that is in your guidance?

Right.

Okay. Is that typical? Because I don't really (technical difficulty) but now it is part of the guidance?

Part of the actuals.

Right. And it is a positive?

Right.

Got it. Okay. Very helpful.

Leon Dubov, Luminus.

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 is different from [standing chart]?

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 is an offset to that up in the revenue line. So there is no net bottom-line impact. So, if you take that out, it is about a 33% effective tax rate.

Okay. So it is just a one-time adjustment this quarter, and it doesn't have a net impact on it?

That is right.

(Operator Instructions) There are no further questions in queue.

Okay. Well, thank you, Danielle, and thanks, everybody, for participating today. 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 we will 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.