Avangrid Inc (AGR) 2016 Q3 法說會逐字稿

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 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 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 US 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 factor 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, www.avangrid.com. We do not undertake any duty to update any forward-looking statements.

Today's presentation also includes references to non-GAAP financial measures. You should refer to the information contained in the slides accompanying today's presentation for definitional information and reconciliations of non-GAAP financial measures to the closest GAAP financial measures.

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're funded by cash from operations, which totaled about $1.2 billion.

In addition, we're 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're doing right now, we're executing on that, and then we will get that built 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 will talk a little bit about that. But we're 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 $0.432 per 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 charges 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% in the year to date, the nine 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 useful 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 will be looking at that, and there is some intercompany transactions that occurred. But the renewable business was actually up about 10% when you exclude those intercompany transactions that occurred in 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. So let's look at the ones we had to date. We had 744 megawatts that were under construction. We've actually added another 66 megawatts of solar on two projects that will now be completed in the 2017 to 2018 timeframe. The Amazon Wind Farm East project in North Carolina that has 208 megawatts is under construction and will be operational by the end of this year. And we have four additional wind turbine projects with a 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're 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, so new benefits for existing wind farms. It will increase the output by about 20% by retrofitting the components. The economics of this turned out to be very compelling for certain sites, which we have identified those sites. And we're going to be offering what we call a blend and extend product to the customers of the existing fleet, and we're 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 want to reach 100% renewable energy for their owned and operated facilities by 2025. So we've signed a 10-year agreement for renewable energy with them in Oregon, where we'll 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 reported in the past, executed 100 megawatts of new and extended PPAs in 2016 with traditional utility counterparts.

Turning to the networks business, we're on track with our $6.7 billion of CapEx for during our forecast period. The projects we're working on mainly are FERC transmission upgrades, replacements, alternatives, electric and gas distribution that's mainly for safety and reliability; infrastructure upgrades, aging infrastructure that needs to be replaced, and then customer service automation. A 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've spent 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 projects. 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 the 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 the 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 a new 20-mile, 345-kV transmission line, one new substation, and expansion of a couple more and reconductoring of a number of miles.

Now, also on the New England Clean Energy IRP, we were informed yesterday that our two network proposals were not selected; however, we're pretty confident in the value and the merit of these projects. And we can see further opportunities with them, in particular, with the new clean RFP in Massachusetts that will be coming about in April of 2017. We've 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 for 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 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 a 9.92 ROE, equity 52%, rate base of a little over $1 billion, and then the three-year cumulative rate request of $98 million, what we found very important is the OCC and the Consumer Council filing actually was reflective of a $27 million increase over the three-year period. Smaller rate base and obviously, a lower ROE, but you can now see what 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 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 a rate cases are necessary, we'd 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 at the midpoint is about $0.04 that we're reflecting.

Wind production in the Renewable business, as I said, we were off about 5% so far is what we're expecting. If we have normal weather through the fourth quarter, or 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 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.

We also, when you see, it looks, 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 operations there, out of gas storage and back into the renewables. So that was actually a positive impact of $0.02 a share. So when you look at that, Renewables was probably overstated a little bit, because it really, we added $0.02 in there. And the gas storage business, which shows off $0.08 was probably really 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 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. So we see the growth in our business as continuing, and the 8% to 10% is still very much doable for us.

So turning to page 13, we're going to remain 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 key for us, so we're actively managing our merchant exposure, trying to turn as much as we can into PPAs. And the rate cases, we're derisking many of the measures. So we've had significant improvement in the year-over-year performance, and as I said, we feel very confident in maintaining the 8% to 10% net income compounded annual growth for the period through 2020.

And with that, I'm going to turn it 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. 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 solid growth quarterly as well, 44%, 43% for net income and earnings per share.

Moving to slide 16, as Jim mentioned, there's 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, above 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 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 the wind and 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 were about $200 million. And we were also able to complete the turbine contracts for some of our wind projects sooner than expected, and so we'd 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 Texas, where we've seen a 4 percentage increase up to 30% as well. Then on slide 21, when we look at the actual gigawatt hours of production, again, driven by the West and South Texas, we are 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, 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 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, we 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 in 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, and that leverage, 24%, same as it was at year-end 2015. And net debt to 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 UI Holding Company debt of $450 million is outside the utilities as well.

So turning to slide 25, when we look at 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 at Renewables as well as the New York rate settlement. Underneath the consolidated result, some of the segments, there's some intercompany changes year over year that have taken place. In 2015, there was a settlement of an intercompany note and 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. And on the bottom part of the page there, mark-to-market changes year to date at Renewables, there's really no net impact. And at the gas storage business, we did see a $0.07 improvement, really with the elimination of that contract in 2015 that was underwater.

On slide 26, Jim walked through the guidance changes, and at the bottom 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 will see how that plays out in the federal regulatory process. As we've 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, commodity prices and volatility also have the potential, both positive and negative, to affect results. And wind production, 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 on the right part of the page, what things impacted our guidance? So Networks, earnings improvement 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 base going forward that were lower than our expectations. On the renewable side, a 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 we look forward to seeing many of you at the EEI conference in early November. And I'll hand it back to our operator, Danielle, for question-and-answer.

(Operator Instructions)

Joe Zhou from Avon Capital Advisors.

Hi, good morning, or good afternoon.

Good afternoon now. Yes.

So would you provide a timeframe for your 350 megawatt of powering opportunity? Would that be 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 Credit. We would anticipate it would be earlier, but Frank, do you want to comment on that?

Hello, Jim. Thank you. No, I think that it's -- we have a number of projects that we could repower over this time. So we're discussion with a number of current PPA offtake 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. Have it completed by 2020. Yes.

Okay. Got it. And also on the Network, since you didn't win Maine transmission in the New England RFP, are you so comfortable to keep your $740 million of growth CapEx, like growth transmission CapEx? I know there's a probability of (inaudible), but are you going to find other projects to fuel that?

Joe, right now we feel pretty good about the number. We'll update that probably when for the -- when we do the year-end results in February. But right now we feel okay because we have a lot of other projects we're looking at, and these will go back in. We're very optimistic about those two projects. They are good projects that should get developed, and we'll be bidding those in into the Massachusetts RFP, as I said, in combination with some hydro providers it looks like, and 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, what is the timing for Massachusetts RFP?

I believe it's April 1, 2017.

April 1, 2017

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

Okay, great. Very helpful, thank you very much.

Sure Joe.

Chris Valea, JPMorgan.

Good morning, guys. This is Chris Turnure. 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 the summer was particularly warm, some of the trading opportunities were not there.

How can we think about that change today versus what you were thinking previously, and then where you might offset that? And then within that, how does the roll off or the continued roll off of the expensive transportation contracts play into that as well?

I think when you look at the -- our expectation would be more around normal weather so that we could actually move some gas out of storage, optimize our positions, and then be able to 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're 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 be able to optimize your asset position and that's what we'll be looking to do. So it's -- the fact that the winter was extremely warm and nothing was pulled out of storage during the year, or very, very little, it didn't give us the opportunity to get much done. Then the summer wasn't a whole lot more helpful, because the way things worked out in the summertime and we're not looking at doing much more for this winter, so we can't project that's going to get any better at this point for the fourth quarter. So that's why we're being a little conservative on this.

Okay, and then other than just weather itself being projected to be normal and 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 a return to some volatility that would allow us to then optimize our positions. That's really all we're counting on; we're not looking, Chris, at doing anything beyond that with the gas storage activity.

Okay. And then same question on the power side of the business, which 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, it had been 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 that it made more sense to consolidate particularly the electricity trading within the Renewable business. And so, because they can optimize their assets a little better that way. So those are the things we were looking to do.

And I think going forward, we'll be looking at, obviously, we have merchant prices that are going to impact us. With where prices are today, and as we said all along, our forecast at 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 sales, we'd like to see prices go up, but we're not anticipating that in our forecast.

Okay, so lab pricing projected forward off of a 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 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 now.

It was the two we had in Maine, the one we were bidding with Emera, which was the Maine reliability and then the MTCP project. So those two that we had talked about previously. 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 I think there was a project too that you had bid with Eversource bringing power from New York state into eastern Massachusetts?

That one was not selected either.

Okay.

All three of the ones -- the two transmission projects then the renewable project we had, none of those were selected.

Okay, and have you disclose how much from those projects was in your $750 million of risk capital?

No, we have not.

Okay.

They asked us to keep it confidential, so until we can get -- talk to the states and determine if that still applies, we'll just keep it confidential for now.

Okay, thanks, Jim.

Sophie Karp from Guggenheim Securities.

Hi, good afternoon. Thank you for taking my question. Can you help me understand the seasonality in your networks business a little better. It seems that, based on your guidance, you are expecting the last quarter to be quite a bit higher versus Q3 and Q2. And so how much of that is the result of normal seasonality driven by the gas business versus the timing adjustments and the true ups that you've mentioned earlier?

The gas business is really driven by heating load, and so as the weather gets colder, we'll finally having some cold weather in the Northeast this week. The fourth quarter is typically better than the second and 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 don't see big seasonality on a consolidated electric distribution business.

My question is, are there any abnormal adjustments that resulted into Q3 this year being that much [over] versus Q4 that (inaudible) 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 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 the New York rate settlement in May/June of this year, so we're seeing the benefit of that now that will continue to pick up in the quarters as we move forward.

Thank you.

Joe Zhou, Avon Capital Advisors.

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

Good, Andy, how are you?

I'm all right just a quick follow-up. I apologize if you talked about it already; I was on another call. With not winning these three projects, and then also I think New York project, I forget what it's called, that was not in the CapEx. But I know the selection on that had been delayed as well. When will you refresh your growth rate, because didn't you give a very robust growth rate, 8% to 10% or something? So when that will that be refreshed

Well, we said today that we're confident with the 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. So we will go from there.

But right now, we're pretty confident. That the projects that weren't selected, the two in Maine, 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 taken with that.

So what -- oh, 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 touched on this as well. So as we look at our growth projects, we 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 beholden to the process.

So specific to Connect New York, this is a project, you're familiar with it, 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 that it did not meet the sufficiency test. That, remember that proceeding 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 BC, it didn't meet the criteria.

As Jim correctly said, this is a project that we think has great promise. We're 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 project. So we're 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're 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 in 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're seeing in the new RFP that will come out early next year is a strong interest in taking projects, predominantly in the past just wind projects, and firming them with wind so you have a more holistic --

Hydro.

I'm sorry, hydro. Thank you, Jim. And so we're 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's a FERC right-line 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 DS IP 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 word on that by, let's say, mid-next year.

So there's a lot of moving parts, but for -- if things don't work out the timeline, we look to substitute other projects and keep moving with these projects that we think have a lot of economic value through the pipeline.

I think the issue is going to be more, as you said, at the very least, on timing. And I would assume that you 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 it's only in the outer years that it's possibly achievable. Isn't that correct?

No, not necessarily. Because, again, we're looking to substitute other projects. Remember this might just be, let's say, a one-year delay or something like that. There are other projects we've 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.

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?

They're all probability weighted, 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, I'm sorry go ahead

I was going to say, keep in mind that the RFP projects were not even going to be operational until 2019 under the original schedule. So we would pick up some AFUDC or some quick 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 compounded growth over the period. So we've never said it was 8% to 10% each year, every year. Some are higher, some are lower, but so we're looking at 8% to 10%. We feel very confident with that. And as Bob said, we have projects we'll put in there and substitute and keep 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's two of them; it's not Fitzpatrick, it's the potential for Ginna.

Ginna, Ginna, I apologize.

There's two large projects that are ongoing: one is called the GRTA, that was the project that we'll have completed by the end of the first quarter of next year that would allow for the ultimate closure of Ginna, should it happen. And there's 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 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 [zecs] that were passed and whatnot. It appears like 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.

And Andy. Andy --

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

They are still needed for system reliability in that area, because of expected low 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 built 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 contribute as well during this timeframe.

We had projected in our original forecast only an additional 650 megawatts being built in the 2020 timeframe. Now we're looking at up to 2,000 megawatts. We don't have PPAs form yet, but we did have PPAs for the 650. But we are feeling pretty good about the 2,000, and we also feel very good about the 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 main projects were a subset of that. So in the overall, it's not that big of an impact.

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

Glenn Pruitt from Wells Fargo.

Hi, thanks for taking my question. Just regarding the 2 gigawatts at 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 about 1,400 megawatts. Now we're saying we still have the 744, we got another 66, which is solar to bring us up to 800. We're saying that we're buying equipment to do 2,000 megawatts -- up to 2,000 megawatts beyond the 800 and 350 megawatts at least of repowering. So we're going beyond what we said before of the roughly 1,400 megawatts.

How much we get done, we'll look at; we're pushing hard, but we wouldn't be buying equipment for 2,000 megawatts if we didn't have some confidence we would 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 the $2.8 billion investment?

No.

Okay, so that's on top of it too.

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

Okay.

No, I'm sorry. No, wait a minute, the $2.8 million was for the 1,400.

Okay, right, right that makes sense.

Okay

Okay, and just one separate, quick clarification. The rate-base adjustments that you mentioned earlier, are those ongoing or a one-time hit in 2016?

Some of both, Glenn. There's some that's timing projects that have moved out of 2016 into 2017, and others, like the clarifications around bonus depreciation would be permanent. So maybe there's $0.02 to $0.03 a share drag resulting from the permanent ones.

Okay, great. Thank you.

Paul Patterson from Glenrock Associates.

Good morning.

Hi, Paul.

Good afternoon, how you doing?

Afternoon, you're right.

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? Now you guys have split Renewables from gas and what have you. But what is the number that you guys have?

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 with the [FERC] transmission, you guys mentioned a risk and an opportunity, the ROE. Could you remind us 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 the 10.57 allowed, and then there's some adders on that that would limit the upside with all the adders to11.74. So it's a blend of that, but that's what we use for our long-term projections at this point. Because we haven't had any definitive decisions by FERC, subsequent to complaint number one.

Okay. We will probably be getting one in about six months, right?

Who knows.

They do seem to run together, okay.

Sometimes. We've got two, three, and four now.

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 you whatever answers you need. So thanks again, and we will probably some many of you at the Edison Electric Institute financial conference. Thanks, Danielle.

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