Avangrid Inc (AGR) 2016 Q4 法說會逐字稿

Good morning, everyone.

Thank you for joining us today for our presentations.

First, I'd like to go over a few logistics before we begin.

We'll begin our presentation this morning with our fourth quarter and full year 2016 earnings results, and then we'll move directly to our long-term outlook.

Following these presentations will be Q&A.

At 12:15, we will break for a light lunch and then we will be welcome to join us for our seminar and Q&A on the Renewables business, which will then conclude at 1:45.

For each presentation, please hold all of your questions for the Q&A sessions as we will not be taking questions during the presentations or the breaks.

Presenting our fourth quarter and full year earnings presentation and long-term outlook update will be Jim Torgerson, Chief Executive Officer; Rich Nicholas, Chief Financial Officer; Bob Kump, Chief Executive Officer of AVANGRID Networks; and Frank Burkhartsmeyer, Chief Executive Officer of AVANGRID Renewables.

Please note that copies of our presentations and press release and also our factbook are also available on our website at www.avangrid.com.

Finally, during today's meeting, we will make various forward-looking statements within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995 based on current expectations and assumptions, which are subject to risks and uncertainties.

Actual results could differ materially from our forward-looking statements.

If any of our key assumptions are incorrect or because of other factors discussed in AVANGRID's earnings news release, the comments made during this conference call in the Risk Factors section of the accompanying presentations or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our website, avangrid.com.

We do not undertake any duty to update any forward-looking statements.

Today's presentations also include references to non-GAAP financial measures.

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

With that said, I'll turn the call over to Jim Torgerson.

Thanks, Patricia.

I want to start with our year-end results, which we had very good results for the year, notwithstanding some of the challenges that we have with guidance during the year.

But for our first year as a company, we did accomplish a great deal, and we're very optimistic regarding the future.

I feel really good about the future.

If you look at the first slide here, after we get all the boilerplate out of the way, fourth quarter net income was $207 million or $0.67 a share and this is on the full GAAP measurements.

Full year net income, $630 million or $2.04 a share.

What's key here, we were executing on our strategic plan.

The capital investments we made were 64% above what we had in 2015.

Now keep in mind 2015 only included UIL for 15 days, but we've spent $1.9 billion during 2016.

We also had our initial integration activities, okay, the initial integration activities, which really we're just bringing together Iberdrola USA and UIL.

Now we're looking at working on best practices, and we're going to be implementing that starting -- going forward.

We did get some very good regulatory relief and stability going forward, looking at our three-year rate cases in both New York and then also in Connecticut, so we have the assurance of getting three years' worth of rate increases and stability and also our capital spending for that matter in both those jurisdictions.

We'll be delivering on our dividend commitments.

The board has declared a quarterly dividend still at $0.432 a share.

That was declared last week and will be payable April 3. We're also planning to increase the dividend in 2018, consistent with our 65% to 75% payout ratio.

Now the other thing I want to mention is the Gas Storage business, which we've said is noncore, we're actually looking at strategic options related to that business now and so we've excluded it from some of the guidance.

We still have the numbers there so you can still understand what is -- what it's delivering.

Looking at our strong performance in 2016, and this again is under GAAP, you can see that earnings were actually up 116% net income and earnings per share, 81%.

Now keeping in mind that only included UIL for 15 days, and we'll get to the adjusted numbers in a second.

Also in 2016, there's a onetime adjustment.

We had a gain on the sale of the Iroquois pipeline of $0.06 a share.

In some of the benefits in 2016, we have rate agreements that allowed for rate relief at least for about six months from -- out of New York.

We did have a little higher wind production and the extension of the useful life for the wind assets.

The production was higher than 2015 but still below what we consider a normal year, and then start of the integration of the companies.

Looking at what we're going to characterize as adjusted net income now and it excludes some of the noncore items, one being the Gas Storage business and also, we exclude any mark-to-market and we're doing that going forward as well.

But also the Iroquois sale and a couple of other items you can see listed at the bottom there.

But adjusted net income was $206 million or $0.67 a share in the quarter, and the full year was $640 million or $2.07 a share.

Now some of the adjustments.

The Gas Storage business lost $42 million or $0.14 a share in 2016.

Mark-to-market was actually a positive in the year of $11 million or $0.04.

Some other onetime items mainly the sale of Iroquois and then an impairment of our interest, actually, was in the Kinder Morgan pipeline was about $11 million -- or $20 million, I'm sorry.

And then including UIL, actually, added $201 million or $0.65 a share.

So now looking at the adjusted earnings.

With all those adjustments, we look at the earnings per share for the quarter were actually flat, and the adjusted net income was basically flat as well.

Now a couple of things I want to mention there.

We did get the benefits of the rate agreement, we have efficiencies, best practices.

Actually, every one of our operating business was improved over 2015, but the effective tax rate was higher in 2016 over 2015 because we didn't have as many credits going forward so -- in that year.

So all the businesses improved, but the earnings ended up being flat because of the taxes.

And for the year, it was up 20% on an adjusted basis from $1.68 up to $2.07.

So we did improve wind production, again not as much -- not normal but better than '15 and the useful life extension.

And as we said, there were tax benefits in both years, 2015 happened to be higher.

Now looking at our capital spending, again, and this did not only include UIL for 15 days, but we spent $1.2 billion in '15 and up to $1.9 billion.

60% of the capital spending was in the Networks business.

The Renewables also included the Amazon Wind Farm U.S. East and some other wind projects under construction.

Also, we have the safe harbor and the repowering purchases of about $200 million in the end of the fourth quarter that allows us now to get the PTCs, assuming we get purchase power agreements to back all those up.

The rate agreements in 2016 really did a lot to enhance our stability, and along with the annual FERC true-ups, we have certainty on about 80% of our rate base, greater than 80%.

So we have three-year rate increases retroactive May 1, 2016, in New York for all of our businesses, New York State Electric and -- both electric and gas, also for Rochester Gas & Electric, again both the gas and electric.

We also got the approval and recovery, the $260 million of past storm costs, so those are being recovered over a five-year period for part of the 10 years for another part of it.

The ROE was 9% based on 48% equity capital.

Now we start sharing 50-50 after a 50 basis point deadband, but it's also calculated on a 50% equity.

So the decoupling and reconciliation mechanisms for certain costs are already in place there and they continue.

The UI electric rate decision was three years as well, started this last January on '17.

The capital plan was approved for all three years.

The ROE is 9.1% and a 50% equity capital structure and the decoupling continues.

Now the dividend.

We pay our quarterly dividend of $0.432 a share.

The board has determined that is going to be the floor.

We are committed to that.

And with a payout ratio of 65% to 75%, assuming the board agrees and the board obviously has seen this, but the plan is to start raising the dividend beginning in 2018.

Some of the major accomplishments in 2016.

One, we had the completion of the 208-megawatt Amazon Wind Farm U.S. East and an additional 536 megawatts are under construction.

We have the implementation of a Safe Harbor Strategy where we have enough invested that we can secure up to 2 gigawatts of wind and repowering up to 350 megawatts.

And we'll talk about what's actually in our long-term plan when we get to that portion of it.

We've announced 66 megawatts of solar.

We have an additional 100-megawatt contract that we renewed and another 70 megawatts of merchant that we've now contracted for.

And as of now, we're in the absolute final stages of executing another long-term PPA at our Montague wind farm for 200 megawatts.

Constructive rate agreements, those provide us great rate stability for us, along with the annual FERC true-ups.

So like I said, more than 80% of our rate base is pretty well determined.

We filed for the advanced metering infrastructure and the earnings adjustment mechanism in December.

We expect answers from the New York PUC sometime later this year, probably the second half.

And we've gotten pretty good -- pretty strong reliability and customer satisfaction scores across all of our utilities, and in particular, in New York, we actually had an incentive that we earned for the first time this last year.

Now it's a small amount, a few hundred thousand dollars, but we actually earned an incentive in our gas business.

Now the first phase of our integration has been completed.

Credit ratings were upgraded during the year for AVANGRID and its subsidiaries.

We had some governance improvements.

We actually added two new independent directors, and we were a finalist in the New York Stock Exchange Governance Award.

So all in all, our governance has been improved fairly well.

When we look at the guidance for 2017, now keep in mind, this excludes the Gas Storage business and any mark-to-market.

But we're looking at a range of $2.10 to $2.35.

And this -- so this is on an adjusted EPS basis.

Networks would be $1.66 to $1.74.

Renewables $0.50 to $0.65 then the Corporate, a charge of $0.08 to $0.05.

Gas Storage, which again noncore, not included in the base numbers but just so you know, it would be $0.08 to $0.12 loss is what we're seeing for the full year of 2017.

When you look at the Networks business, we're going to have a full year of the NYSEG RG&E rate cases, the UI rate case and then the full integration efficiencies and best practices.

And one other thing to note is that was in the numbers in Networks before, now has moved to Corporate.

We had the -- UIL has $450 million of debt that has moved up to AGR.

So that's part of AVANGRID now and not shown in Networks.

So the interest expense that would have been there before is now part of Corporate.

We're also assuming we have normal wind according to some of the historical averages in -- that are 2011 to '14, it's really -- a net capacity factor, 31.4%, almost 32% is what we really see for the net capacity factor for our existing wind farms.

Last year, it was really -- it actually was closer to 30%, I think, rather than the 29% that we have there.

We'll have a full year of the Amazon Wind Farm this year in 2017.

Again, we're excluding any mark-to-market.

We'll report it on GAAP but for guidance purposes, it's almost impossible to say what that's going to be.

And the full year extension of the wind assets, the useful life now will have the full year of that revenue, part of year as we did last year because we couldn't get all the leases assigned appropriately.

And we're also assuming a federal tax rate of 35%, so wherever that may end up.

Now a couple of key opportunities and risks in 2017.

And again, the earned distribution ROEs, the distribution companies, we expect to earn the allowed returns at a minimum.

FERC transmission ROEs, there's several cases going on.

There are four complaints.

We've assumed that it's the one that would give us the 10.57% return as a base and up to 11.74% as the cap on that.

That's kind of the assumption, I think, we're looking at right now, but we'll have to wait and see what FERC determines once they get a full commission.

Right now, they're down to two commissioners as you know so they don't even have a quorum.

So whenever that occurs, then we'll look at what the transmission ROEs will be.

Federal tax reform, I think, all of you know is going to be something that's being pushed in Congress or will be.

We have a slide in our long-term projections that show what the impact on us would be but there actually could be minimal to no impact to slightly positive.

Wind production, again, that's assuming it's normal.

That's what we have in our plan.

It hasn't been in the last two years.

It's been a little bit below.

So hopefully, it'll pick up this year.

And we have to execute on our capital projects, our O&M.

But basically with what we have today, we should -- we are -- we're very comfortable with the guidance we have and then we're getting to the long term, we'll talk about the 8% to 10% growth.

Merchant wind prices, again another risk or an opportunity depending which way they go.

And also then implementing our best practices.

So now, I'm going to turn over to Rich, who's going to talk about the financial results.

Thank you, Jim.

Good morning, everyone.

Thanks for joining us here today live in New York and thanks to those who are online with us.

For those online, I'm moving to Slide 16 now.

I'll do a little deeper dive into the results for last year.

And as Jim mentioned going to this concept of adjusted net income, we're really looking to focus on the core business going forward, be as transparent as possible as to the results and be responsive to the comments that we received from investors over the last year around things like mark-to-market.

And so that's why we moved to this concept of adjusted net income, again looking to be as focused on that core part of our business as we could.

So the adjusted net income up 23% for the year versus 2015, and looking at the bottom right side of the slide where we break out what happened -- what comes out in that adjustment, as Jim had mentioned, removing mark-to-market, profits or losses from sales on investments and then taking out the noncore.

All of that on a rounded basis, rounds to a $0.03 change, and so that's how we end up at $2.07 for adjusted net income versus $2.04 on a GAAP basis.

So turning now and breaking down by segment.

As you can see on the pie chart on the left side, adjusted net income, Networks still is the biggest part of our business, 75%; Renewables, 15%; and Corporate actually contributed 10% last year due to some of the tax items that Jim mentioned.

Some of our states have introduced a unitary tax regime over the last couple of years, New York in 2014 and Connecticut in 2015.

And you actually pick those up the following year when you file the returns for those years.

So in 2016, we have about $0.11 of unitary tax adjustments resulting from those schemes.

It actually hurt the Renewables business but was positive to Corporate.

So no change on a consolidated basis for that item.

But when you do look at the Renewables results, they look a little low for the year compared to what we're guiding for next year.

You would add back that $0.11 to take out that adjustment for the unitary taxes.

Also there was a settlement in Maine around some deferred tax flow-through items that added about $0.02 to Corporate as well and another transition rule in New York that added about $0.02 in the Corporate segment.

As we look forward to '17, that should normalize, although we have to file taxes in 26 states, so you can never be absolutely sure exactly how that unitary tax is going to work out.

The other thing that happens in the unitary tax regime is sometimes, states will change their allocation factors, whether it's -- there's a three-part allocator based on sales, assets and payrolls.

Connecticut just changed to just sales only, so depending on the relative position to other states, again, that can move taxes around.

Turning to our cash flow for the year, very strong cash flow from operations, basically equal to our capital spending, our cash CapEx for the year.

A little bit of cash left over and with some debt that we picked up during the year.

We fully funded all of our CapEx, all of our dividend requirements.

And most of the spending, as Jim mentioned, was in Networks, and even with that, we still had $137 million of available cash from operations from the Networks business.

The Renewables minus $53 million but we did spend the $200 million right at the end of the year around the safe harbor purchases.

So turning to Slide 19 where is our debt -- our leverage really is primarily at Networks, which you see, almost 84%.

At Corporate now, we have the -- what had been the UIL holding company debt that was incurred back in 2010 to purchase the three gas local distribution companies.

That's moved up into the Corporate segment.

The UIL Holdings is really just an intermediary shell holding company now.

And that's a drag of about $0.04 on Corporate going forward, the interest on that debt.

A little bit of short-term debt at the end of the year, $152 million.

And then we have some tax equity financing that is amortizing off at the Renewables business.

We continue to have our $1.5 billion credit facility and a $1 billion commercial paper program backed up by that credit facility.

So when we look at just a couple of key credit ratios, our net leverage that just ticked up a little bit from 24% at the end of '15 to 26% at the end of '16 and net debt divided by adjusted EBITDA still very strong at 2.6 times.

Our credit ratings for the year, AVANGRID, the holding company now is BBB+, pretty much across the board.

And many of our subsidiaries also were upgraded in Connecticut and Massachusetts as a result of adding specific ringfencing provisions that came out of the merger agreements.

And for AVANGRID Holdings, Iberdrola, S.A. was upgraded, which helped our overall rating as well.

There are important reconciliations in the appendix between GAAP and non-GAAP, and at this point, I will turn it back to Jim to begin discussing our long-term update.

Now I got to get through all the appendices and go to the next presentation, which is going to load up in a second as well.

But let me start while they're loading this up.

First off, I'm really enthused about our long-term outlook.

I mean, when you think about it, we're probably arguably one of the highest growth rates in the industry.

And what I want to do today and with our team is explain how solid this really is and how doable it is.

So I think you'll find that all of us really feel very good about where we're going, how we're going to get this done and that it's just a very solid opportunity for us.

So when you look at this, we have, as you know, eight regulated utilities in Connecticut, Maine, Massachusetts and New York.

We have 3.2 million customers, $8.7 billion rate base.

Okay, that's all nice.

We really consider ourselves to be the utility of the future.

We're expanding our investments in infrastructure improvements and also in the grid information modernization, so we're already doing the things that people are talking about for the utility of the future.

We believe we're already there plus with our Renewables business.

We're the second largest generator of electricity from wind in the U.S. and we have 5.9 gigawatts installed today.

We're expanding our renewable business with greater opportunities, and it's all -- much of it secured by the safe harbor.

We have 2 gigawatts that are already secured for that and then the repowering of the 350 megawatts.

Our financial strength, we have very little leverage.

We have really robust cash generation and the support of the Iberdrola Group.

So we have significant capital investments and growth opportunities and a commitment to increase the dividend now.

And so the other thing we mentioned already but we are exploring strategic options for the Gas Storage business.

When you look at what we really are, we have diversity, experience and opportunity.

So look at our assets and regulatory diversity, that provides stability and predictability that you want to see in a company like ours.

We know, like I said, 80% of our rate base and Networks, we already are either determined or are in the FERC assets are done annually trued-up.

We have strong growth opportunities in our regulated assets and our contracted renewable business.

We have great cash flow, have a strong balance sheet.

We won't be a cash taxpayer through at least the time of this forecast period, 2020.

Annual dividend floor of $1.728 with increases expected to begin in 2018.

And we'll have the continued implementation of the utility of the future with the focus on advanced metering infrastructure and the smart grid initiatives.

Looking at our adjusted -- and again, this is adjusted earnings per share.

We're reaffirming the '14 -- 2014 to '20 CAGR at 8% to 10%.

We're also rebasing the 2016 to '20 off of 2016 at 8% to 10% as well.

And you'll see how solid this is in a few minutes, keeping in mind it does exclude the Gas Storage business and any mark-to-market.

So for net income and again, this is -- for 2016 we had $630 million, our estimate for 2020 is in the range of $870 million to $950 million or 8% to 10%.

Adjusted EPS starting at $2.07 going to $2.80 to $3.05, again 8% to 10%.

Adjusted net income actually is a little higher, $641 million because of the adjustments that were made.

So that again still in the same range and 8% to 10%.

Adjusted EBITDA is also 8% to 10% going from $2.8 billion to $3 billion by 2020.

So keep in mind what those adjustments are that no mark-to-market going forward and elimination of the Gas Storage business, or at least not including the Gas Storage business.

We're reviewing what we're going to do with that at this point.

Look at our capital investments.

$9 billion to be invested in the '17 to '20 timeframe, so $2.25 billion a year.

That's about up 15% from the previous plan.

The increases in opportunities in Renewables with the safe harbor and then in Networks with the advanced metering infrastructure and some investments in the grid modernization.

And if you look at the, really Networks because of those changes are about -- it's almost the same, up a little bit year-over-year for the forecast period.

Renewables is the one that's really up and that's because we're adding another 600 megawatts to our forecast over what we had last year.

Now 200 megawatts we now have operating so that comes off, but we also have 50 megawatts in our forecast for repowering.

So we've upped it from -- last year, we said we had 1.4 gigawatts of -- during the forecast period.

Now we're saying it's 2 gigawatts but 200 megawatts already went operational so it's up a little bit.

And 50 megawatts for repowering out of the 350 megawatt we're eligible to do, so we're not forecasting everything at the moment.

We're really confident in our long-term outlook with the investments.

When you look at it, 73% of the investments are what we call secured at this point.

In Networks, 91% are in -- we have been determined in rate cases already for investments that we're going to do.

So the only thing that's left is 9%, and those are what we call highly likely.

That's the AMI and the distribution improvements, which we fully believe will get approved by the New York Commission, but they haven't been yet so we're putting that in the highly likely category.

And just to further elaborate, there are no risk-adjusted projects included at all.

We haven't included that one bid, so none of the transmission projects we had last year that were subjected to an RFP are included in our forecast.

Now that would give us another at least $500 million in Networks we could invest that's not even in the forecast today.

In the Renewables business, we've already secured 43% of the forecasted amount that we said, which is another 1.8 gigawatts, okay?

So 17% are in what we would characterize as advanced stage negotiations right now.

And then the balance where we have -- we believe we'll get another 40%, which is about another 600 megawatts that will be built, we feel very confident of, but we don't have the contracts yet and we're not negotiating contracts.

We're discussing it with counterparties.

So when you look at the total, 85% is in the secured or highly likely category, which we think will be done very soon.

15% is in the likely category that we would characterize.

And keep in mind also have the ability to build another gigawatt under the safe harbor and 300 megawatts that we can then repower that again aren't even in our forecast at this point.

So look at rate base growth.

It's going to go from $8.7 billion to $11 billion.

That's 27% increase by 2020.

80% of the regulatory stability, we've already determined.

New York, all those -- all the capital spending's been determined there for the rate base.

UI, both the transmission and then in CMP, the transmission as well.

But in UI, it's a distribution and transmission.

So $5.2 billion of our investments, we're going to make in the Networks business are already secured.

The [only] that isn't is what we call highly likely, advanced metering, which was approved in New York for ConEd already.

We believe we're going to get it.

They want it for the REV process and then the distribution improvement program, which is the grid modernization.

So those are the two that are in the highly likely category.

So rate base is going to grow about 7% over the '16 to '20 timeframe.

And the adjusted EBITDA is 7% to 9% for the Networks business.

Now looking at Renewables.

Installed capacity's going to go up 1.8 gigawatts, and that will be wholly built with 100% with PPAs, so we'll end up with 7.7 gigawatts by 2020 at a minimum.

We have -- when you look at it, '16 to '20, we had 2 gigawatts more what it is that we had 1.4 gigawatts last year.

We actually had 200 megawatts that went operational this year, which was the Amazon Wind Farm.

So including that, we're really at 2 gigawatts that we're going to add.

The net capacity factor, again to give you a little more information, with the technology, the location, the improvement in technology for the wind turbines themselves, we're looking at new wind that will have a 40% net capacity factor.

Our current operating portfolio is about 31.5%.

New solar, which we're going to be adding 226 megawatts, that's what's in our plan, the net capacity factor for that is 29%.

Production from projects with PPAs will increase about 73% in 2020 versus 66% last year.

The installed capacity will end up being about 69%.

So the adjusted EBITDA for Renewables will be up to 9% to 11% in 2020, so that's the growth rate we see for that business.

Now integration, process optimization, best practices, we put in a program that we're calling Forward 2020 and this is for all of our businesses of AVANGRID.

What we want to do is become in the top tier of efficiency in the industry.

And a lot of that's going to revolve around innovation, how do we innovate with our people?

We are looking at site consolidation.

Right now, we have 160 buildings of different sizes and shapes, leased, bought, owned, whatever.

We're looking at least 50 of them to determine, do we -- can we consolidate those?

Do we need them to get more efficient with that?

Our fleet optimization.

We have 4,000 vehicles of some sort.

We're looking at reducing that 10% or 400 vehicles.

If you can imagine the vehicles, you have maintenance on those, you have fuel.

We don't -- we've determined we probably don't need as many as we have, so we're going to reduce that at least by 10%.

Grid automation and digitization that will improve the system efficiency.

This is another part of our best practices.

It starts with AMI but then goes beyond that.

And using help from Iberdrola Group, we figure we'll be able to improve our automation and then get more system efficiency out of that.

We're targeting also hiring to attract better talent, skills for the utility of the future.

You look at this, we have 25% of our workforce is eligible to retire today.

40% will be eligible by 2020.

So we have an opportunity -- I mean, it's a little concerning, but we also have an opportunity to bring in people with -- that can fit the skill set that we're going to be needing as the utility of the future, more innovative, more strategic thinking, people with better technical backgrounds.

So we're looking at this as a great opportunity so we'll use attrition to be able to fill these roles that we see for the future.

Now we're also will be looking at standardization and consolidation of our IT systems.

How do we make them more consistent?

Right now, we have different systems from the mergers and mergers that go back to NYSEG, RG&E, CMP, and then with the Renewables business.

We're going to be looking at how do we consolidate these to get more efficiencies out of our systems.

So what we look at is O&M as our net operating expense as a percentage of adjusted gross margin.

We're looking to drive that down from where it was in '15 and '16 of 36%, 34% down to less than 30% by 2020.

So we'll be driving the O&M costs down, pushing and working to move our gross margin up at the same time.

So we can do that with Renewables.

We have rate cases that are already in place that are going to help us, and it's getting more efficient with all of our operations.

Now we talked about our noncore business.

We're going to manage to mitigate the risk going forward.

We're looking at it strategically to see if it fits at all and what do we do with it.

So the Gas Storage business is not included in the adjusted EPS CAGR.

But even if we did include it, we'd still would be at the 8% to 10% because it's very de minimis.

You can see in the last line through the planning period, the loss is expected to decline about $8 million to $10 million by 2020.

So we're exploring strategic options.

The adjusted gross margin is positive and it's improving, but we still lose money out of it because we have about $25 million of interest cost and about $25 million of depreciation in that business.

So it's a big hurdle to get over initially.

We have actually some very good assets.

We own the storage facility at Katy, Texas where we have, I think, 14 transmission pipelines that come into there.

So we have some very good assets but the margins are so thin, we're not making enough money out of it.

And we have contracted storage as well.

Transmission revenue is breakeven as some of the out-of-money contracts that were there rolled off in 2015 and '16, has negligible impact in '17.

Mark-to-market, minor to breakeven as we manage the volatility going forward.

And as I said, the finance costs and the D&A are negative but we know they're not going up.

So the net losses are going to continue, but we expect it down to $8 million to $10 million if we still have it in 2020, so to give you some ideas on that.

Now this is probably one of the more important slides.

Not that they all aren't important but this gives you an idea of why we're so confident in our forecast.

We have our base adjusted net income.

50% of the growth is coming from secured CapEx Networks investments.

So these are the ones that have already been approved by regulators.

Another third is coming from secured CapEx renewables.

These are PPAs we already have signed.

So if you look at this, we would have a growth rate of 6.5% to 8.5% CAGR if we don't do anything else other than what's already been approved, already signed up for.

So now the other things that are going to get us to the 8% to 10%.

We have AMI, which hasn't been approved but we're highly confident that's going to occur and grid modernization.

We also have PPAs that are in negotiation right now we're talking about.

So they're in the advanced stages we're characterizing it.

We have best practices that we're going to be implementing we see.

So when you look at that, that's why we're very confident in the 8% to 10% growth we believe we can get.

When you think about this, we've already secured 6.5% to 8.5% if we do nothing.

We've already got those approved.

So with that, I mean, you got 83% of secured investments in our growth plan today.

Now when I look at our financial strength, the net debt to adjusted EBITDA in 2020 is going to be at 2.8 times, probably a little less but Rich will keep it down.

Net leverage will be around 34%.

So we'll still be in great financial position.

The dividend.

We're very confident in our growth and that looking at the long-term outlook, we're planning to increase the dividend beginning in 2018.

Right now, the floor is at $1.728 a share.

Payout ratio, we're looking at 65% to 75%.

So the increases, we expect to achieve a payout target and begin increases in 2018.

And to give you an example, at a 70% payout ratio with our earnings per share CAGR, that would result in a dividend of $1.96 to $2.14 begin in 2020, which would be somewhere between 13% and 24% increase in the dividend from today's level.

Now looking at tax reform.

Taking our earnings today of $2.07, we have our 8% to 10% growth.

If we get a 20% tax rate and elimination of the interest deduction, that would actually be a positive for us by about 4% because we have most of our debt, we only have $450 million of parent company debt that we'd have to absorb.

The lower tax rate obviously would be beneficial for our Renewables business whereas, obviously, the Networks that's going to get passed through but also the -- any interest that we're not being able to deduct should get passed through as well.

Now then if we have immediate expensing of capital, that'd be negative 3.5%.

So you can see, if all those things happen, we'll still be 8% to 10%, and it actually could be slightly positive for us.

So this is based on our analysis of what could occur from the potential legislation.

For our 2020 Forward program, we're looking -- the vision we have is to be best-in-class in the industry.

We want to implement our best practices to drive the top-tier performance.

So when we look at consolidating office locations, as I said, there's 50 of them, more than 50 we're looking at right now.

We want to optimize our fleet, optimize our purchasing.

We actually get very effective pricing, but the timing, it seems there's a lot of delays in getting the purchasing process.

So we're pushing to get that done quicker, faster and more effectively, along with every best practice we can bring into the business from what Iberdrola has rolled wide and anything else we can find that's going on in the industry.

Talent attraction is something we're very focused on.

We want to attract top talent in all areas, and we're partnering with top universities today already.

We're going to be driving innovation and technology deployment.

In New York, we have the energy smart community.

We're looking at battery storage and our Renewables control center actually operates every -- all of our wind assets across the U.S. from one control center, and it's amazing what they can do with -- look at avian mitigation, whether they're bats or birds, looking at how to -- when do we shut down the turbine so they're not -- the birds and the bats aren't getting struck by the turbines when they're migrating.

So many things we're doing that are on the cusp of new technology that we're implementing today.

We want to deliver customers solutions and they have high-quality service.

So AMI, new customers care systems, they all enable a customer to better manage their energy use.

In the Renewables, we're customizing our C&I products.

That's what we're focused on right now.

Many C&I products we see because the opportunity with utilities have kind of slowed down, we're focusing on wherever we can -- the business can be, and we bundle packages for our C&I customers.

Also, we have a continued focus on safety and reliability.

We have an unwavering commitment to top quartile safety performance and reliability, so we want to create value for not just the shareholders but our customers and our employees as well.

So executing on our strategy to deliver 8% to 10% growth in adjusted earnings per share, we got to focus on our core business.

We want to maintain our financial strength, and we will be implementing best practices while we're committed to value creation and increasing the dividend.

So with that, I'm going to turn it over to Rich and then Bob and Frank will follow along.

Thanks, Jim.

So just a few more slides on the financial aspect and then as Jim mentioned, we'll get into the more details around the businesses themselves.

But with that 8% to 10% adjusted EBITDA growth, as we look out in time from an EPS standpoint, the Networks business would still be about three-quarters of the contribution, 76%; Renewables, 28%.

In Corporate, that's the interest expense on the holding company debt.

And as we look to the future, we will need to raise some holding company debt in addition to the $450 million that's there in order to fund the overall capital program.

We also have other options for that, whether it's tax equity or project financing but right now, we've assumed it'll be up at the holding company.

On an EBITDA basis, since really the holding company drag is all interest, there's no holding company slice there.

So Networks is about 71% and Renewables 29%.

So just to spend a few moments on where we were a year ago versus where we are now.

Again, being responsive as we can be to some of the requests that we've had and how we've really focused on the core business going forward.

So left column is where we were last year at this time, right column is where we are now.

On the pricing on the Renewables business, pretty similar, flat pricing going out in time, both for energy and for the RECs and PPAs in that $54 to $56 per megawatt-hour.

On a net capacity factor basis, last year, we were projecting around 32%.

This year, we've broken it out separately between 31.5% for the existing wind farms and 40% as the technology has improved on the new wind farms coming into service.

Last year, at the beginning of the year, we had not included anything for the useful life extension, reducing depreciation at Renewables.

We now have that in at basically $0.14 a year benefit compared to where we were last year.

Similar effective tax rate at 35% on the federal basis.

Last year, we did have the Iroquois sale that we were aware of at the beginning of the year.

Obviously, that's behind us and we've not contemplated any other onetime items going forward.

And Gas Storage was included this year and now going forward, we have taken it out as noncore.

So turning to Slide 23.

Our CapEx last year for five years was $9.6 billion.

Our new 4-year plan '17 to '20 is $9 billion but if you include the capital that we've actually spent in '16, it would be just around $11 billion, so up $1.4 billion on a comparable basis.

As Jim mentioned, we did have some probability-weighted transmission projects in there last year and we've taken those out.

We've updated the wind estimates to include some of the safe harbor and repowering.

And we've put in CapEx for the AMI project in New York and the smart grid project in New York as well.

Last year, we did not have any solar in our plan.

This year, we've got a modest amount going forward.

And we have not put in those probability-weighted projects.

And we've also not included anything yet for Connect New York but potential DC line running down the New York Thruway.

All of these things will be subject to RFPs.

Offshore wind, we've talked about before, is really just beginning to emerge opportunities to bid for projects and would not likely have much of an impact through 2020.

And there's always other transmission projects that we're looking at but we've not included them in the plan.

So our leverage does pop up a little bit as I mentioned earlier, because we have increased the capital spending over the period.

And net debt to adjusted EBITDA just under 2.8 times.

So looking at our funding, how we're going to pay for all this as we move forward.

Cash from operations, still very strong over the period.

We generated about $8.6 billion.

Our total debt would go up about $2.7 billion to fund all of our needs, including dividends over that period.

And to support the CapEx program of $8.9 billion.

So just slightly, free cash flow negative before dividends.

And the bulk of it is in the Networks business where we'd need about $500 million of incremental funding and $200 million incremental at the Renewables business, absent the dividend payment.

So with that, our leverage ratio does go up by the end of the planning period to around 33%, 34%, and the net debt-to-EBITDA goes up from about 2.5 times, 2.6 times today, up to 2.7 times to 2.8 times.

We're under 2.8 times at the end of the period.

And we're well positioned for potential tax reform, depending on how that happens.

The details truly will matter in this case how that gets enacted.

As you all know, what goes into Congress and what comes out of Congress often are very different things, so we'll be watching that very closely and participating through our industry associations, EEI and AGA.

Also, during the planning period, we do have some debt that matures over that -- the timeframe, about $1.5 billion primarily at the operating companies.

And in 2020, again, that $450 million of former UIL debt will come due as well.

But all very manageable over that period, and the existing tax equity we'll amortize away through 2018.

So our financial strategy really has a lot of flexibility and opportunity.

Expect to generate almost $9 billion in cash from operations.

We got strong access to both the debt and equity capital markets, although our plan does not envision any need for equity, given the capital spending that we've laid out and our current leverage ratios.

And we have an intercompany money pool that allows us to move money around to where it's needed.

And our existing $1.5 billion bank credit facility was a five-year facility that also has opportunity to extend at various points in times.

The tax equity market is still available, although there's a lot of wait and see on tax reform, exactly how that's going to be impacted but that is a potential vehicle for us if we find that it makes sense economically, as well as project financing in the Renewables business.

And we do not have any plans just to confirm that for any Yieldco vehicle.

We really don't see the need for that we can raise capital cost effectively without it.

So with that, I'll hand it over to Bob Kump to talk about the outlook for the Networks business.

Thank you, Rich.

Thank you, Jim, and good morning, everyone.

I'd like to start this morning by really thanking the 5,000 men and women that make up Networks.

We had a really, really good year in 2016, and Jim and Rich spoke about our financial performance but there's so much more that goes into running a utility.

And I just wanted to touch a little bit on those before I go into the presentation.

So Jim touched on safety.

It's something we stress every day, and it's something we strive for zeros, and Jim mentioned we have a near-term goal of being top quartile.

So in 2016, our lost-time injuries and our motor vehicle incidents were down 10% relative to 2015 so good performance there.

We want to do better, we want everyone to be safe but good performance.

Operationally, we measure ourselves on more than 50 different metrics, and many of them also were measured by our regulators.

And we made every one of those (technical difficulty) this year.

In fact, Jim mentioned that for the first time, based upon the rate agreement we reached last year in New York, we were able to earn a small incentive if we were successful at reducing leaks on our gas system, and both NYSEG and RG&E earned the maximum incentive of 5 basis points on equity in 2016.

Also, we -- regularly, our utilities are recognized by various third parties for their excellence in customer service and satisfaction.

A couple of examples this year, we had very high marks from J.D. Power, CMP and NYSEG were ranked first in the east for electric and combination utilities, for brand recognition by Cogent's.

UI got a recognition from the EPA on its energy efficiency program.

So you can see that kind of across the board, we really pride ourselves on excellence and operations, we had a very good year.

We've made great progress on our capital spending, great progress from a regulatory perspective.

And so I think it really sets ourselves up well for the next three or four years.

So just to start, two points I'll make on this slide.

Number one, and Rich and Jim spoke about this, we have a significant base of capital investment that we're looking to make over the next four to five years, focused not only on the electric side of the business where you know there's a lot of investment needed to modernize the grid, upgrade the grid to allow for new forms of generation and demand response like we're seeing in the REV proceeding in New York.

But also in the gas side of the business where we continue to see very good growth despite the fact that oil prices are low and creates sometimes a hurdle for us.

And then second, by having eight utilities in four different jurisdictions and the regulatory constructs around those, including, for the most part, RDMs at all of our companies, with the exception of two smaller companies and a lot of true-up mechanisms.

We really think that we have a solid base of diversification to provide both stability and predictability to our results.

So as we think about the growth drivers for the business, there's really four.

And the first is kind of setting the solid foundation for growth by having good rate agreements in place.

And we had excellent success in 2016 in terms of the three-year agreements we reached at NYSEG and RG&E, electric and gas as well as at UI.

And Jim mentioned the statistic that when you take the rate base associated with those companies and you add to that the rate base associated with our FERC-regulated transmission, which is updated annually, that 80% of our rate base that we now have certainty on for the next three years.

Second, I'll call it our core, our base CapEx.

So it's focused on distribution, upgrading, modernizing the system.

It's looking at REV-related principles in New York, so fully rolling out AMI, for example, automating the system.

It's looking at gas expansion, and it's looking at from a transmission perspective, and this is the third piece, what can we do to help solve the energy issues that we're facing in New York and New England?

And where we're trying to reach certain RPS standards and quite frankly, in many instances, the transmission system is not yet up to the task.

And then lastly, and this is an area that we made good progress on in 2016 and much work to be done going forward, and that's our focus on continuous improvement, okay?

Everything we do, we challenge whether we're doing it the best way.

And we constantly look for best practices across our utilities and quite frankly, across all of Iberdrola where they've been very helpful in this regard, looking at ways to run the business as efficiently as possible.

What from my perspective makes this very important as you think about all the investment that needs to get made in the system, be it distribution or transmission.

Everything else being equal, that can create some significant rate pressures for consumers.

So we have to be as absolutely efficient as we possibly can to offset those rate implications for our customers.

We strive in our utilities to have the lowest distribution rates of any of the utilities in our region.

So here's the base CapEx plan.

It's $5.7 billion through 2020.

As Jim mentioned, we had taken out any probability-weighted investments, so this is kind of core investments if you would.

It does include, and I'll get into it a little bit more, I have a slide, in a minute, AMI, which we view as being very highly likely to be put in place because we have other utilities in New York that already have had AMI approved for their systems.

Beyond that though, I can say that we have a portfolio of projects that we're working on the transmission side that we feel very optimistic about, and we think can add significantly to the growth numbers you see here for the Networks business.

So looking at rates, I'm not going to repeat what's been said already in terms of the agreements that we reached in New York and in UI in Connecticut.

I'll just say that our focus this year from a rate perspective is on three companies, it's CMP distribution business, CNG and SCG are two gas businesses in Connecticut.

Of the three, I would say at this point, probably the one that's going to be in most in need is going to be SCG.

It's been out the longest and it doesn't have an RDM whereas the other two do.

But I can tell you that we're looking at everything we possibly can to minimize or potentially avoid rate increases to my point earlier about trying to maintain our rates as competitive as possible.

Okay.

Let's stop now for a second and just go to New York, just a couple of slides here.

You're probably aware that in New York is a part of REV, the commission is giving utilities and opportunity to earn up to 100 basis points of incentives for meeting various targets within the overall REV initiative.

We made a filing in December that essentially focuses on four areas, in system efficiency, getting load factor of the system up, reducing the peaks; energy efficiency, helping consumers use energy more wisely and to conserve, that's where AMI and time of use rates come in; interconnection, how quickly and how efficiently we are at helping distributed generation interconnect; and then our success around helping the state with the clean energy standard.

So those are the four areas.

We've made the submittal, we'll be working with the commission hopefully by summer timeframe.

We have a result in terms of exactly what those metrics will look like and what our opportunities are under the EAM.

AMI, I mentioned this earlier so we're looking at full rollout of AMI in New York for NYSEG and RG&E, electric and gas, it's about 1.8 million meters, slightly over $0.5 billion investment.

We made this filing in a very similar manner to what other companies in the state have done, showing a very similar benefit to cost ratio.

We fully expect to get this approved again sometime probably in the middle of this year.

It is our hope and it's something that we're working through as we speak.

In the meantime, we have a very interesting project, we call it the Energy Smart Community that we're doing in Ithaca, New York.

And that includes the immediate installation between now and August of 19,000 meters electric and gas in that community.

What we're really doing in Ithaca is we're creating essentially a microcosm of what we view the utility of the future to be.

So were taking all of the components of our DSIP filing that we made last year and we're applying them in Ithaca to see how they all work in one community.

So whether that's how we manage the grid and optimize the distribution network, how we forecast and look at solutions to issues on the grid using DER, DG and other technologies, or how we enable the customer to use energy more wisely and to be aware of the services that are out there for them to use energy more efficiently.

All of that's going to be done within, if you would, a microcosm of the Ithaca area.

The goal this year is essentially to implement and put in place all the technology.

And then next year, we will essentially assess and monitor how all that's working.

And from that, to the extent necessary, we'll tweak our DSIP plan that ultimately gets rolled out across all of the service territory.

So we're really excited about this.

No one else in the state is doing this.

It's about $26 million investment that we get recovery through a specific rate adjustment mechanism that came out of the last rate case.

Flipping over to transmission.

So this is just a snapshot of where we are today.

We have about $2 billion of rate base.

You can see that about two-thirds of it earns the full ROE cap.

It's really comprised of those 3 large projects you see there that were put in service in the last few years.

Jim touched on the fact that at this point, we've had four complaints on the ROE in New England.

Complaint number one has been resolved.

That's what results in the current 10.57% base and 11.74% cap ROE.

We have complaints two and three where ALJ has issued a recommendation.

Four is in its infancy.

I really can't tell you at this point when these will get resolved because of the situation we have now, we don't even have a quorum.

But we do expect probably at least two and three will get some resolution later this year.

My hope would be with where interest rates have gone, everything that we really don't see a measurable change from where we are now but it remains to be seen.

So as we think about growth, we continue to believe very strongly that Maine holds great promise for being a part of the solution to all the RPS standards and the needs of New England.

And I say that for a couple of reasons.

One, experience.

We completed, as you know, a $1.4 billion upgrade of the main system a couple of years ago, we called MPRP.

Did that on time, on budget.

And through that entire process, we got tremendous support not only from legislators, politicians but our regulators as well as communities, believe it or not, who view this as an opportunity for economic development.

We created over 3,000 jobs during the construction of that project.

So as we look at other opportunities in Maine, we have two projects here that we had submitted in the previous RFP that the results of which were disappointing because they didn't really grant a lot of what they were originally we're looking for but we think hold great promise.

That's MREI and MCPC so one project you see going to the north, one going to the West.

Again, key here is where working with the communities over the long term.

In past, we've been very successful at acquiring right of ways.

And for these types of projects, we have virtually all the right of ways in hand.

You know that typically, what trips up these types of large projects are right of ways and community support.

And again, I think that's where we see Maine being a really great place to invest.

The other three on this page, MEPCO, Lewiston Loop and Mid Coast are actually all kind of offtake, to some extent, of the MPRP project that we completed a couple of years ago.

One of them, Lewiston Loop is already under construction.

MEPCO, we just started.

Mid Coast, we'll be starting up here later on this year.

In aggregate, these three account for a little over $250 million of spend, and they are in our base $5.7 billion of investment.

In terms of New York, so we really have three areas of focus.

In western New York, you'll recall that last year, we submitted a project working with the New York Power Authority to alleviate congestion there.

Made it through the first round, so we expect a final resolution and hearing, who's going to win that award on the second half of this year.

We continue to progress a project we call Connect New York.

This is an underground DC line essentially from Utica through the congestion points into the city.

We think this holds great promise for a number of reasons: number one, the congestion, I mentioned, is significant.

It results in consumers downstate paying billions of dollars more than they should be for energy; number two, if you ask Frank, all the best wind quality in the state is off the eastern edge of Ontario in the Adirondack Park.

And again, it needs transmission to get to the most attractive market, which is New York City; number three, you have nuclear plants upstate that while they're being supported now by this concept of ZECs, zero energy credits, we view that as more of a short term and longer term, you really want to get the infrastructure in place to again allow them to have access to higher prices in the city; and then lastly and most recently, the announced shutdown of Indian Point.

So all of these point to the need for greater infrastructure in the region.

And this is a project we continue to move forward with.

And we're hoping that later this year, there'll likely be another solicitation within which we can submit this project and we will have it ready for that.

And then the last one is New York Transco where we're working into the consortium of all of the utilities on projects.

They have a significant project right now in the AC proceeding this ongoing that we hope to have some resolution on later this year.

And then lastly on gas.

We see significant opportunity on the gas side as well, focused on thee areas, so first, we have 2 LNG facilities in Connecticut that need upgrade.

And so we're going to be spending about $85 million upgrading both of those facilities this year into next year and a little bit into '19.

We spend a lot of time and focus on safety as I mentioned earlier.

And so we're spending a lot of money on leak prone pipe and replacing aged infrastructure.

And you can see here we're talking close to $600 million between New York, Connecticut and Massachusetts over the next five years.

And then lastly, as I said, growth.

We continue to see good opportunities for growth.

I think in the last three years, we had six new franchises.

We're looking at some additional franchises, mostly in Connecticut.

Although we are also working up in the Plattsburgh area of New York in terms of growth.

So good opportunity there.

We're probably going to spend in the $230 million to $240 million a year on growth over the next three or four years there.

So in closing, I just want to say thanks for your attention.

We really feel optimistic with regards to Networks and its outlook for the future and again, premised on those four items.

I'll reiterate, number one, you need a good foundation and I think we've done that in 2016 with the rate cases that we completed.

So we're in good shape there.

Number two, really executing on the strategy on our base investment, modernizing the grid, putting in automation, allowing for new technologies, DER, DG and the like is going to be a big area of focus.

Number three, and I think this is an area where we have the opportunity to hit some real homeruns on, are some of these large transmission initiatives that we have going on in New England.

And then lastly, the focus on continuing -- continuous improvement and efficiency through best practice is something that we focus on every day and I think will contribute as well not only to near-term better performance but longer term, lower prices for consumers.

So with that, I thank you very much for your attention once again.

And I'm going to turn it over to our clean up hitter, as always, Frank Burkhartsmeyer.

Thanks, Bob.

As Bob said, I'm Frank Burkhartsmeyer, CEO of the Renewables business.

And like Bob, on the Networks side, we're really enthusiastic about the opportunities ahead over this plan.

I'm going to give you some of that and then later, we're going to have a seminar.

If you're able to join us, we can -- you can meet some of the team that's going to be responsible for executing on that.

And I think you will definitely get a sense.

There's a very rich opportunity set here, and we really have the team to deliver in this moment.

So just a bit of highlight for those of you who might not be familiar.

We -- AVANGRID Renewables is the second-largest renewable wind operator in the U.S. with 5.9 gigawatts now installed with the addition of Amazon Wind East.

We've got a pipeline for wind and solar of about 6.5 gigawatts, 5.5 gigawatts of that is wind, about 1 gigawatt is solar.

And we build these projects primarily from our pipeline.

We build this pipeline over years, and we harvest it and with the intention of owning and operating these.

We're not in the business of building for sale.

We're in the business of building to operate.

Our operations are managed, as Jim mentioned, out of a state-of-the-art control center in Portland, Oregon.

We can operate the whole fleet from there.

We've invested heavily in our technology there.

It operates around the clock, and we operate in seven organized electric power markets as well as the WEC.

Finally, we are focused on providing unique energy solutions in the renewable space as the C&I market we'll talk about a little bit later is an area that is looking for this, and it's really an area where we feel we provide leadership to the industry.

And finally, and Jim already mentioned this, all of our new projects will be with PPAs and just a good thing to mention.

What are the growth drivers in our industry right now?

The market looks very good, robust through 2020, I'd say.

Wind and solar has never been more competitive with traditional generation as a sustained reduction in levelized cost of energy has continued.

In addition, many buyers of renewable energy see it is a good hedge against carbon risk in the future.

This competitiveness is underpinned by support of tax incentives.

We have the PTC extension, we've got the ITC on solar.

And we also have PTCs available for repowering.

So there's strong support on the policy side.

And on the demand side, we continue to see strong growth, in particular right now from the commercial and industrial sector where they're looking to green up their portfolios, respond to their customer and stakeholder concerns about carbon.

And many of these customers are seeking additionality.

What that means is they want a new wind farm built.

They want to be able to contribute to the greener future directly and tangibly by having a wind farm that they can claim essentially as their own, and we're happy to provide that.

I'd say finally, the growth plan continues to be supported by state-level renewable portfolio standards that require utilities to serve a portion of their load with renewable energy.

This is still an important component of the growth but at this moment isn't as key to us as a commercial and industrial.

We think a little bit later in this plan, that will start to take -- have a bit more importance to the utility customers.

So probably most importantly, let's talk about what our build plan is here for the next four years.

You can see, we have a robust pipeline.

I've already mentioned that, which is paired with our Safe Harbor Strategy.

We've secured 2,000 megawatts potential wind build for the next four years as well as the repowering.

And we also have a solar pipeline.

Right now, we have secured 802 megawatts beyond the 206 megawatts that have just come online -- 208 megawatts at Amazon East.

So we've got another 800 secured, that is 736 megawatt of wind, which includes one 200-megawatt PPA that we're just in the process of concluding and execution right now at Montague.

And then we've got the 66 megawatts of PV solar, the Gala and WyEast projects that we told you about last time.

Beyond that, we have another 400 megawatts where we are in negotiation.

We are in advanced stage negotiation with counterparts on some wind projects that we feel highly likely opportunities to come to market.

And then what we would consider likely, this is another 590 megawatts of wind and solar.

These are the advanced stage development projects.

They're in markets where their customers are looking for these types of projects, and we feel very good about bringing these to market over the course of this plan.

So between 2017 and 2020, we've got 1,800 megawatts in this plan that we feel very confident about, of which 800 have PPAs at this point or have PPAs being executed at this point.

Beyond that, because we did safe harbor for 2,000 megawatts, there is another 968 megawatts of wind available at full PTC value during this period.

If the market evolves, if we're able to harvest more of our pipeline, of course, we'd be very happy to bring more wind projects and we certainly have the balance sheets to support that.

I want to talk a little bit here about C&I origination.

It's something that we, I think, there's some mystery maybe to some people about it and where our space, of how we fit into the space.

But this is not a new sector for AVANGRID Renewables.

We actually have a long history of dealing with this type of customer.

We've secured over 400 megawatts of new wind projects, with commercial and industrial customers as well as 56 megawatts of PV solar.

We also, I think, about this time, a little bit later last year, announced the Nike transaction, which wasn't our new project but we want to take some of our existing merchant capacity in the Pacific Northwest to meet their rather sophisticated needs for green energy.

This is a good example of the type of work that our origination team is doing to meet the needs of these customers.

They're trying to customize products that work specific to their needs around energy management.

We are well positioned to continually lead through, leveraging our intellectual capacity -- capital.

Our demonstrated commitment as an owner operator is very attractive to a number of commercial and industrial customers.

They want to know that the generator is still going to be there, that we're the ones that they're going to deal with.

Our reputation in this space for developing and constructing in a responsible manner is also important to many of our customers.

And our energy management skills, which I talked about and we'll talk about a bit more in our seminar later are also very important to some of these in terms of customizing the offering that they are looking for.

On the repowering side, as Jim mentioned, we have 350 megawatts of equipment that we've safe harbored at the end of this year last year to allow us to repower equipment through 2020 and get full PTC value.

We also have another 20-megawatt project that we bought equipment for late last year as well as a 22-megawatt project with the rest with GE.

We have the tax legislation here allows existing wind farms to qualify for new PTC if they fulfill certain requirements.

Primarily, you had to have secured 5% of the cost last year, and you need to replace 80% of the fair market value during the repowering.

What you get for this is you get better -- you get new equipment, you get upgraded aging equipment, you increase the output typically, and you get to 23, 24, 20 -- whatever the PTC will be at that point for the next 10 years.

This strategy has strong economics with the potential to extend PPAs as well, so we see this is a really attractive area for the future, and we will take advantage of it to the extent that both our wind economics and the economics of our sites and of customer is aligned.

We haven't built a lot into the plan.

I'll tell you right now, we just have 50 megawatts.

I think Jim already mentioned that 50 megawatts in this -- the numbers to date, but it's an area where we can do quite a bit more.

Finally, offshore.

This has been touched on a little bit, and it's really mostly falls outside of the planned scope but it's a view of the future.

DOE has a very long range plan.

86 gigawatts of offshore wind they expect by 2050.

More importantly to us, we are seeing from North Carolina up through Massachusetts, we're seeing a lot of interest in offshore wind.

BOEM auctioned a wind energy area off of New York in December.

We participated in that auction.

We didn't win it but it was very competitive and the site went for $42.5 million.

Gov.

Cuomo announced a 2,400-megawatt offshore wind, I guess, initiative by 2030 following the Indian Point closure agreement.

Massachusetts passed legislation last summer for 1,600 megawatts of offshore wind.

And the BOEM will be doing an auction off of the Kitty Hawk auction off of North Carolina in March, and we are a qualified bidder in that and we'll consider bidding as well.

The point about all of this is that Iberdrola, we have a strong relationship obviously there.

They are a leader in offshore wind.

We have a big footprint in New England, in the East Coast.

We have a strong position in renewable energy, and we really see the offshore market as likely to be something worth paying attention to in the next decade, and we are going to position ourselves to make sure that our natural strengths are ready to go if this market does evolve as we hope it does.

So I guess just to finish on a strong note that beyond 2020, there is -- the PTC will phase out but there are other growth opportunities out there.

And we're excited about the next four years but we're also excited about the 10 years after that.

I think there's a lot of investment in clean energy out there.

So with that, I will turn it back to Jim.

Great.

I think we're going to go from here.

There's one chart here on our Gas Storage business that just gives you a little information about it.

Basically, like I said, we have some very good assets.

The Katy Hub is -- has like 14 interconnects into it and we have other storage facilities.

But we're going to be looking at strategically what do we want to do with this business over the next few months and we'll get back to you on what we intend to do in the not-too-distant future.

So with that, I'm going to open it up for questions now and feel free to ask.

I assume we're going to have microphones passed around since this is being audio broadcast that people can hear what questions you may have.

So there's a few to start.

Mics are coming up from the back here.

Once you ask your question, I'll repeat it if I can hear you.

And basically, just first off, on New York, specifically.

What is your assumption on REV particularly -- specifically the incentive (inaudible - microphone inaccessible) base plan?

Yes, the question is from the New York REV process and I assume the energy adjusted mechanism, what's in our base plan.

So Bob, do you want to --

Yes, since we don't really know what is going to happen there, I think we've been pretty conservative in terms of an assumption until we see exactly what transpires from that proceeding.

As I mentioned, probably midyear, sometime in the summer, we'll have clarity in terms of how that proceeding comes up.

Okay, great.

And then also for the Renewables segment, just help me put together the dots here.

How many new PPAs have been signed that are in plan as confirmed versus what we saw last year at the Analyst Day?

Last year, we had 744 megawatts that we had confirmed with the under construction with PPAs.

We've added 200 for a new wind farm called Montague and we've added 66 megawatts for solar.

And then we've actually added another 70 megawatts which [becomes] a merchant facility that we have a PPA now with Nike.

And Frank, then we actually had another 100 megawatts that we -- extensions.

But new build, just to clarify, a 66 megawatts of solar and the 200-megawatt wind PPA.

(Inaudible - microphone inaccessible) Capital.

Just to continue on the renewables front, it may have the impact (inaudible - microphone inaccessible).

But first, just the growth rate, the CAGR of 2.5% to 3.5%, that's off of what number?

No, the 2.5% to 3.5% is the piece that makes up the 8% to 10% growth.

So 2.5% to 3.5% of that growth is coming from Renewables.

Right, right.

No, I understand the CAGR of the Renewables is larger.

I'm just wondering what's the base renewables, is it $0.50 a share?

Is it $0.60?

Is it $0.40?

You're referring to that graph where we split it between --

Yes.

So you have your CAGR of 8% to 10% and then I'm just curious what the base is for the renewable.

Yes, it's off of 2016.

Is it a normalized number?

Or is it $0.37?

$0.37.

Okay.

So you're not normalizing that for normal wind production or anything like that?

No, we did not.

Okay, got it.

And then the merchant portion of your total portfolio after you've secured some of these PPAs that the 100 -- the 70 megawatts and I think there was 100 also that you got extensions on.

How much of the portfolio now is merchant?

To date?

To date.

It is in the factbook, by the way.

Oh is it?

Okay, I apologize.

No, it's about (multiple speakers).

It's about two-thirds today, yes.

About two-thirds.

About two-thirds of production is in -- is PPAs and a third is merchant.

A third is merchant, okay.

And then in the factbook too, again, I apologize.

Do you -- on the merchant portion, do you give a price assumption?

Yes, and it's also in the plan there.

And I don't have the slide in front of me, but I believe we showed that it's $27 to $28 over the life of the plan.

And then you add in the REC value that's also listed in there.

Right, right, right.

And that's based on what like year-end?

Current forward curve, but it's very liquid (technical difficulty) liquid portion of the curve, yes.

Quite flat.

This is Sophie Karp, Guggenheim Securities.

Two questions.

One on the Renewables, one on the utilities.

So on the renewable, you have 1 extra gigawatt that you're kind of contemplating, but it's not in the plan yet and my question is what's holding you back maybe at this juncture putting this in the plan and like firming that up?

And then on utility, my question is, as you contemplated the implication of the tax reform and lowering tax rate, as I understand the regulatory account, and it could result into a refund to your customers on your deferred tax liability, which you have at about $3 billion right now.

So I was wondering how much of the cash refund that could be, and how do you find that?

Thank you.

Yes, the 1 gigawatt, and Frank can deal with this, but basically, we took what we felt was a conservative plan that would allow us to get looking at how much we could add reasonably, knowing full well that if the PPA market does keep developing, you got utilities come in, they want to meet RPS standards or we get more C&I, that we have that ability to add even more construction and build it up further because we have it grandfathered in effect because of the safe harbor provisions.

So that 1 gigawatt, we feel very confident with what we have in our plan.

The 1 extra gigawatt, we feel a little less confident.

It doesn't mean we can't get it done, but we didn't want to put it in the plan.

Secondly, on the tax reform, if they do not change the 1986 Tax Reform Act, which would allow for normalization of any tax benefits, they would go back to customers.

They go back over the life of the assets.

So it would be -- any refund will go over the life -- so over let's say 30 to 40 years, whatever would end up being.

Assuming they don't touch that, that's how it would occur.

If they change something then yes, the commissions will decide how fast the tax benefits do get pushed back to customers and what the cash impact will then be for us.

So right now, it should be over the life of the assets so long as they don't change it.

Well, Frank, do you want to add anything about the --

No, Sophie, we had 1,400 megawatts of growth in the initial plan a year ago, and we felt very comfortable adding 600 megawatts to that.

We, as Bob said -- or Jim said, we do see that there's some potential to go beyond that, but we want to put forth a plan where we can have line of sight towards what projects we think we would bring forward.

This is what we feel most comfortable, saying this is the foundation for a strong plan.

We think it's an ambitious plan and we're excited about it.

But we'd like to leave that extra room in there, and we'll see how the market evolves and keep this dialogue going.

I think the other thing to keep in mind, we have, what, 6.9-gigawatt pipeline too of projects that we can do.

So we have the pipeline there to do it.

It's getting the PPAs agree to, and we don't want to get too far out ahead of that.

So that's the basis for it.

Believe me, I'd love to see another gigawatt added in the next year, a few years too.

And that's what I'll be pushing Frank to do.

Yes?

David Sunderwirth, Bank of New York Mellon.

And thank you for the presentation this morning.

My question is for nobody in particular, but I agree with you, a lot of opportunity in the renewables space.

I'm wondering if you could maybe just give us some of your thoughts around storage and what that might look like in terms of the connective tissue between wind and solar.

You're talking about electricity storage?

Battery storage.

Battery storage, yes.

Right now, where we see it is as it develops and I think most would agree that the storage is not totally competitive yet today but it probably will be at sometime in the future.

We would see storage being at, let's say, the substation level, where you can then utilize it to help in the distribution system and then also for the transmission.

So you're bringing in the -- into your system, into the grid and using it almost as an instantaneous generator is kind of the way to look at the way storage would operate.

Using that with the renewal business, whether it's solar or wind, being able then to store the electricity and then use it as needed is something we see would be actually very beneficial.

Now to do it in bulk and to have enough capacity to be able to actually store it for and utilize it when, let's say the wind doesn't blow, the sun's not shining or whatever, you're going to need a lot more storage than we can see today.

But I know AES is doing a lot with their storage and they're doing a lot of projects with it.

So we're going to -- we're looking at that pretty closely, and Bob, you may want to add onto this.

Yes, David.

So a couple of things to Jim's point from a Networks perspective.

So we are testing batteries, kind of at the substation level and a couple of the areas, one in Connecticut and then one is likely as part of the Energy Smart Community.

And this is quite frankly, the whole battery technology area is one where we're leveraging off of the works being done from Iberdrola perspective on utilizing battery.

So as much I'd say right now on the test basis on the trial basis, but we do see some application going forward vis-a-vis completely redoing a substation, delaying that by putting some batteries in for a period of time, so.

It's Nancy Doyle with MetLife.

Question on the cash flow again from the lower tax rate.

Your appendix indicates that you are expecting lower cash flow as a result of a lower tax rate, taking into account your comment on the normalization of deferred tax liability.

But that, coupled with a slight tick-up in leverage that you're planning and also increase in the unregulated portion of your business, could put downward pressure on your ratings.

I was just wondering if you are willing to defend the high BBB ratings, or if you were comfortable before in the mid-BBB and you would be okay with that going forward.

Yes.

Even with the potential for tax reform, we would still have very strong ratings given where we're starting from.

We think that's one of the things that differentiates us from some of the others in the industry and when you're coming from a 24% or 25% net debt to total cap ratio, we've got room to absorb some of that without jeopardizing the high BBB rating.

Maybe I'll just add too that, philosophically, at the utility levels, we're very cognizant of capitalizing them consistent with the rate plans that are in place.

And so, for example, we're typically, I think, over 50% equity at all of the companies and I wouldn't see that changing.

We would again adjust as we move forward to ensure we're optimizing, if you would, the capital structure relative to rate plans we have.

And Renewables would actually see a cash benefit from a lower rate.

I wanted to get a sense as to at least to start, I guess, in 2016 and 2017 if we look at your rate case numbers that are guided.

Why does it seem like you're earning significantly above your authorized ROEs?

Is there kind of parent leverage or something that we might be missing in our calculation?

And then also specifically '17 versus '16 year-over-year change in Networks EPS.

It's a pretty big growth number around 7% to 12%.

I know you're getting another kind of five or six months of rate benefit in New York.

Anything else in that number, tax rate change, anything of that nature?

Well, one thing that's there, is we moved the UIL debt out of Networks and the interest expense there has gone up to the parent so it's increasing --

$0.04.

Yes, $0.04 right there.

So [Rich]?

Yes.

And then beyond that and I said before, we strive and push our companies to earn at or above and into the sharing bands of our various regulatory agreements that we have.

So yes, we target to earn higher than the authorized return.

And there's no risk to that in your plan when you guys go in for another round of cases in the 2019 time?

Well, I mean, the risk is always that -- sure, I mean, you find best practices that allow you to be more efficient.

If you going for a rate case, presumably you give it back.

We also typically have the flexibility, say, maybe we just stay out and don't have to go in for a case.

And you have to look at as you forecast forward, where do I forecast my returns to be relative to where our regulators currently authorizing returns and you make that judgment as to whether you can stay out.

Our preference, as I said, from rate perspective, we'd love to stay out and just not go back in.

But recognizing the amount of investment, we're going to have to make that sometimes gets difficult.

Also at '17, we'll have a full year UI distribution rate increases.

There was no effect in '16 from that step-up.

At all, yes.

Just as a sort of follow-up on that, I guess.

What is -- how should we think about what you guys are exactly planning in terms of getting into the earnings sharing band?

Is that what we should be thinking about in terms of what your forecast include with the state utilities?

Yes.

And as I said, that we target and we push the organizations to earn into the sharing bands so not just to the authorized return but beyond that.

Okay.

And then in terms of the ROE at the transmission company, is Slide 36 pretty much what you guys are expecting to have in terms of -- because your guidance includes pretty much what you have in Slide 36.

Yes.

Right now, it's premised off of the results from the first complaint, which is it says there was a base transmission ROE of 10.57% and ROE capital of 11.74%.

Do we have -- and I apologize if I missed it in the appendix or something.

Is there a sensitivity that you guys have, 50, 100 basis points if that changes.

We did not put the sensitivity in the plan.

It's not in the projection.

It's not in the debt.

Okay.

Would you like to share it with us if you have it off the top of your head or -- if you don't, that's okay, we can follow up.

We'll follow up.

And then the AMI, the demand reduction that's associated with that, how much is that?

How many megawatts or what kind of a percentage of --

I can get you, it's a matter of public record.

The benefit cost analysis we did -- I can get you the details of that.

It's about a $500 million investment overall.

In the AMI?

In the AMI alone.

Right.

No, I'm just -- and I know that (multiple speakers) --

Yes, you're looking at the savings, essentially what are the components --

Well, I just was wondering what it might do to load growth.

That's all.

ConEd, I know was trying to get this thing dotted.

I think a large amount of that depended on the load growth reduction.

I was just wondering if you guys knew it off the top of your head, that's all.

Okay.

Well, just a follow-up on the transmission sensitivity, a 50 basis point change in the transmission ROE is about a 1% change in consolidated EPS.

So as we get out to 2020, $0.025 to $0.03.

I just want to make sure -- I don't know if you answered the question correctly or maybe you didn't understand my question.

Just back on the Renewables because if you take the $0.37 base for '16 and you look at your growth rate of 2.5% to 3.5% CAGR off the base number, off the base, not for Renewables and if you look at your guidance for '17 and what I don't know, $0.50 to $0.55, that's 48% growth rate off the $0.37.

So that would imply that the Renewable business would not be growing after that based on your charts.

And I'm just thinking that maybe the $0.37 is not really the base.

No, the $0.37 is the base, but you can't look at the growing 2.5% to 3.5%.

What we're saying is of the 8% to 10% growth, 2.5% to 3.5% is because of the growth in Renewables.

And it's -- would add, I think we've given whatever the number [were].

But Jim, if you're growing from $0.37 to $0.55.

The first year, yes.

Right.

That's a big pop and then after that, that would almost imply most of the growth.

That's why I'm thinking that the base is incorrect.

I don't think we gave a CAGR for Renewables explicitly, did we, Rich?

Right.

But it's off a much lower base than what you were going to earn in '16, and that's my point.

And I don't think -- is that really what you're -- because that then would imply a kind of a flat earnings trajectory after '17.

I think the confusion may lie as to how -- I wish I had the graph up ahead -- [at the front].

But it may be is how that graph could be understood.

I mean, the growth on the Renewables CAGR is greater than the 6% to 8%, 8% to 10% (multiple speakers) how Contributes to the AVANGRID growth as growing from 27% too.

But it seems that most of that growth is occurring in '17, is that correct?

Well, you need to look at it --

We can talk about it afterwards.

I'm just confused by it.

Look at the EBITDA growth, which wouldn't be impacted by taxes, and that's at 9% to 11% of what we're talking about for the Renewables business.

And really the impact we had in '16 on the Renewables was a higher tax rate because of the split between that Rich was talking about, which is about $0.11 a share if they went from Renewables to Corporate.

If we start with $0.37, yes, it seems like it's all in the first year.

But you look at EBITDA, we're growing 9% to 11% and that eliminates the tax impact.

So it is growing.

We maybe could look if we normalized out that what the CAGR would be different.

Off of a different base.

We don't have that math on hand, so that's something we can look at for you.

Because I don't think we disclosed the growth.

What other questions -- way in the back.

[Raquel], you got a keep moving.

They're making you run around today.

Sorry about that.

Michael Lapides from Goldman Sachs.

Bob, when you look at the New York transmission projects, which of the ones do you think have the potential to move earlier and which are the ones are really kind of post-2020, post-2025 timeframe [on]?

Yes.

So when you look at the three that I have listed there, western New York is first, we'll find out second half of this year whether we're the winning bidder on that.

Then the projects that Transco has in the AC proceeding would be up next a little bit behind that in terms of time line.

And then Connect New York, we're thinking that there'll probably another some form of public policy proceeding later this year into early next within which we could introduce this project.

So that would be the order, Western New York, Transco, Connect New York.

And can you put some capital dollars around those three, just kind of what they are for AVANGRID's portion of those?

Yes, unfortunately, I don't think we've disclosed, Michael, any of those at this point, the bids for the first two have been confidential and then the third one as well is kind of in its infancy.

I would say this, I can get you some numbers on relative size, how many miles of what and that'll give you, I think, a pretty good sense for what the scale looks like.

Great.

Thank you.

And finally, when you're thinking longer term about offshore wind, do you think the greatest opportunity is owning the wind plant or moving the transmission wire that connects the wind plant?

And is there a significant advantage in being able to do both?

I think we'd like to have both, mainly because the transmission -- you're going to -- what will happen is you'll have a package deal.

I mean, based on the RFPs we're expecting, you'll have to have the transmission and the energy components embedded.

And so that's what you're than to be selling is my guess.

So obviously, we'd like to do both.

And we have transmission expertise obviously, and we have offshore wind expertise from Iberdrola.

I mean, they have four very large wind plants offshore right now that are either built or under construction in Europe.

So we have the expertise, and we're actually working directly with the people at ScottishPower and Iberdrola overall on looking at the wind potential offshore in the U.S. today and transmission, I think we'd like to see both obviously.

What else?

Yes?

Abe Azar from Deutsche Bank.

If capital expenses -- expenditures are a lot to be deducted right away on the tax reform, do you have a backlog of projects that can help make up that earnings gap?

Yes, I think as we showed in the one chart that if you have the lower tax rate, and you lose the interest deduction and then the capital expenditures fully deducted, we'd still be at 8% to 10% growth.

Now do we have a backlog?

Yes, we probably have.

I think we saw in the presentation all the projects Bob was talking about from transmission.

We have in the $500 million that we could look at right -- that we could be evaluating that aren't in our plan at all.

And that's kind of the minimum.

So yes, we can feed in more projects.

The question is, make sure they're economical, make sure we can get them done, but it's not going to affect the 8% to 10% growth rate either way.

So we see that as a plus for us.

Just because we have such low leverage and very little debt at the holding company that it's -- most of it will just get passed through the customers, we're assuming.

It has in the past, on things that get changed like that.

Huge tax changes typically get passed through pretty easily to consumers.

One way or the other, either if it's a benefit to them or a cost, so.

Yes?

[Colleen Kylie] from [Tazina].

I just have a very high-level question on your guidance.

Based on what I'm seeing, the long-term guidance in terms of EPS hasn't changed but the CapEx required to get there has increased.

Is that, in fact, the right interpretation?

And if so, what are the offsetting factors that have -- are leading to slightly lower return on your capital?

I think the answer to that is we took out a lot of the transmission projects that were in there, and they would have been at probably the higher return and now we have more the distribution projects, which are probably a little bit lower.

We've increased the renewable piece and the spending, but we're probably not going to see a lot of the revenue because those are more at the back end in the '19, '20 timeframe when they are going to be coming in.

Because if you looked at, we're adding 600 megawatts, we don't even have PPAs for those yet, so that's going to be more back-end loaded too.

So I think that's the two explanations that I would see as to why we're spending a little bit more yet we still have the 8% to 10% growth.

Yes, I think, Jim, when you looked at that and if you look at what we showed a year-ago for our Networks rate base versus what were showing now is actually lower now because we've taken all the probability-weighted investments, but substituted in large part more solid investments like the AMI and the REV to some extent to offset it.

And likewise on the Renewables, we've added probably 400 megawatts into 2020, which you won't see in the CAGR because it's going to hit in 2021.

First question just on Slide 9 in the long-term update.

The $500 million of Networks projects not in the plan, the RFPs, is that just the New England, the MREI and CPC?

Or is that all of the transmission projects being probability weighted in there?

It's not -- no, it's not all of them, but it is a vestige of kind of the way we looked at it a year ago in terms of potential probability rated.

I would say that overall, when you look at our total portfolio of potential projects we're looking at, I could easily see a couple of examples where if we just hit one of them, it's a home run and blow through the $0.5 billion.

So that's, I guess, a vestige of the old probability weighted, but it's clearly not all of them.

Some of it is distribution as well.

It's not just transmission projects.

Okay.

But that $500 million number is probability weighted of a bunch of different things basically?

Yes, to be very frank, I wouldn't put a lot of weight on the $500 million.

Personally, our goal is to find a lot more than $500 million.

And that would just be the $500 million within this planned period, some of those projects would extend out beyond.

Would extend out beyond.

That's right.

That's right.

Okay.

And on the Renewables side, so you're still assuming that the flat $26 to $28 a megawatt-hour for merchant wind, could you maybe put any context around how much downside you can endure there within the 8% to 10% growth?

Well, just to put it in context, that's at current -- basically current liquid gas market prices and power prices.

So that's -- you'd have to -- I'd say I would leave that up to you to say what you think the commodity range would be upside, downside on that.

And so $26 to $28 is pretty modest average merchant power price across the fleet at this point.

We're not quantifying the downside at this point.

We have -- there's a sensitivity - it's what?

10% move in price up or down would impact consolidated earnings by about 1%, so again, $0.025 to $0.03 per share by 2020.

And last one just on the dividend in 2018.

Is there -- is the idea to just get within the payout target?

Or are you guys going to try to get it to the midpoint pretty quickly?

Obviously, we want to get it into the range.

That's what we're really looking at and then stay in the range going forward.

So we're looking to get within the range.

I'm not necessarily saying it's the midpoint or it's the low or the high end.

But we do feel pretty strongly that we will be able to increase the dividend in 2018, so.

I'm going to clarify a point, the second question about the 2020 investment.

I think I said 400.

It's 200 additional megawatts in 2020, not 400, so.

Any other questions?

Okay.

I think the next thing we're going to do is we're going to take a break.

There's going to be lunch for those who want to hang around and then we're going to go into the Renewables seminar, I guess, we're calling it.

Starting -- that starts, what 12:30?

At 12:30.

So we'll be back in here at 12:30.

So thank you.

Feel free to bring your lunch back in at the table, folks.