Avangrid Inc (AGR) 2018 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Second Quarter 2018 AVANGRID, Inc.

Earnings Conference Call.

(Operator Instructions) As a reminder, this conference call may be recorded.

I would now like to introduce your host for today's conference, Ms. Patricia Cosgel.

Ma'am, you may begin.

Thank you, Joelle, and good morning to everyone.

Thank you for joining us to discuss AVANGRID's second quarter 2018 earnings results.

Presenting on the call today are Jim Torgerson, our Chief Executive Officer; and Doug Stuver, our Chief Financial Officer.

A team of AVANGRID officers will also be participating in the call to answer your questions.

If you do not have a copy of our press release or presentation for today's call, they are available on our website at www.avangrid.com.

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

Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in AVANGRID's earnings news release, in the comments made during this conference call, in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our website, avangrid.com.

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

Today's presentation also includes references to non-GAAP financial measures.

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

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

Thanks, Patricia, and good morning, and welcome, everybody.

As you will see, we are continuing to successfully execute on our long-term plan.

However, the second quarter was negatively impacted by a significant number of storms.

For those storms that were minor ones and there were many, we really can't defer the costs for future recovery at our utilities.

We also experienced transmission outages and start-up costs at 2 of our newest wind farms that had significantly reduced our planned generation.

Having said that, the earnings for the quarter were $107 million or $0.35 a share.

The adjusted net income was $128 million or $0.41 a share.

For the first half of the year, the earnings were $351 million or $1.13; and adjusted net income was $371 million and earnings per share $1.20, which was up 1%.

We are reaffirming our full year guidance, which was initially put out as of February 20, 2018, although at the lower half of the range.

When we talk about implementing our strategy, we have executed a contract for new wind farms -- a new wind farm of 158 megawatts.

We have 497 megawatts onshore wind and solar currently under construction.

In the second quarter of 2018, rate cases were filed for Berkshire Gas and Connecticut Natural Gas and new rates for United Illuminating and Southern Connecticut Gas went in January 1, and for the New York companies, May 1. We also completed the sale of our Gas Storage business.

Now we are making great progress since we received the RFP awards in Massachusetts.

Our partnership of Vineyard Wind, as I think all of you know, received the winning bid for 800 megawatts offshore.

And our NECEC transmission project was selected in the Massachusetts RFP.

We have executed the 20-year contracts which were filed yesterday by the EDC.

We're also very happy to be able to fulfill our commitment to increase the dividend.

We've raised the third quarter dividend to $0.44 a share.

That was declared by the Board on July 11 and it's payable October 1.

Turning to Page 6. You can see the results in a graphical form, which I just went over.

The earnings per share were down 2% in the first half.

The adjusted earnings per share were up 1%.

The first half earnings per share includes 2 months of the Gas Trading business and 4 months of the Gas Storage, which was sold May 1. And it also -- the adjusted earnings eliminate the Renewables mark-to-market restructuring and some other charges.

In the first half, Networks was up 4% to $0.90 a share or $280 million.

Included in that were the network rate plans, which added $45 million to gross margin.

Not -- as you know, not all of that goes to the bottom line because we have increases in O&M, depreciation, interest and so forth that, that is expected to offset to recover along with our profit.

Now the impact of those minor storms and the related costs was a negative $0.07 a share for us in the first half of the year.

Renewables was up 19% to $0.37 a share or $105 million on an adjusted basis.

Production was up 12% year-over-year.

The new Renewables are -- the megawatts we added in production, added $64 million in margin, but that was not all of it because we had some start-up issues and transmission issues -- we had an internal transmission outage that lasted about a month at Tule, and that impacted our new production by about $0.05 a share negatively.

So between those 2 with the $0.07 and the $0.05, we're about $0.12 for items that we could put in the noncontrollable category.

We're pursuing obviously best practices and efficiencies.

The wind generation was actually down slightly about 2%.

The West and Texas were up, New England -- or North East and the Midcontinent were down.

From a corporate standpoint, net interest -- and this was remember, last year, we moved the debt off of the Gas Storage business to Corporate, so that affected us by about $0.03 a share because we're not getting the income from that any longer since it's been sold.

And then we had some discrete tax items that were positive in 2017 of about $0.04 a share.

I think all of you remember, last year, our effective tax rate was lower than I think most people expected because of these onetime items.

Now turning to Page 7. We are reaffirming the outlook for 2018.

Our earnings per share of $2.16 to $2.46 and adjusted earnings per share of $2.22 to $2.50.

We are guiding to lower half of the range due to those first half impacts related to the storms.

We also have a delay in the Earnings Adjustment Mechanism in New York.

We now believe that won't occur until 2019, and then the start-up issues and transmission outages at our new wind farm which I just mentioned.

We are actively pursuing mitigation measures to overcome as much of this as we can, through the best practices and the operating efficiencies that we are continuing to pursue.

We're also now looking at selling some Renewables development projects.

This is a strategic decision in looking at evaluating the pipeline of projects we have and more specific projects to see if we can generate greater value by monetizing them today versus waiting for several years to have them go get a PPA and then go into production.

So we're evaluating that on a near-term basis, which we do every year anyways.

But this is getting a little more emphasis because we have a 12-gigawatt pipeline right now, and we want to make sure we're monetizing the value as quickly as we can.

The wind performance is a risk and a plus.

I mean, it was [off] about 2%.

If it improves over the last half of the year, we could see an uptick.

Timing of capital spending -- and then storms.

We've had a number of storms.

Now fortunately, June has been a little quieter, but the first half of the year, we had more storms than we've ever seen.

And then taxes and regulatory.

We're also, as of today -- or really as of February 20, '18, reaffirming the 2016 to 2020 earnings per share growth rate of 8% to 10% and then the '16 to '22 growth of 8% to 10% as well.

We're still highly confident in being able to achieve those longer-term growth rates.

Turning to Page 8 on our Renewables.

We did execute a contract for 158 megawatts for a new wind project with a C&I customer and that will be going into operation at the end of 2019.

So our secured contracts in the long-term outlook now totals 1,605 megawatts.

That's 83% of the original target we set for 2020 and 58% of our 2,744 megawatts we set for a target for 2022.

We have 497 megawatts under construction, the Wy'East Solar, which will be operational later this year.

We have about 9 megawatts right now out of the 10 that are actually producing energy but not delivering.

Montague, it will be late 2019 as well as Karankawa.

Turning to Page 9 with our Vineyard Wind project.

This is the joint venture we have with Copenhagen Infrastructure Partners on a 50-50 basis.

It was selected in the Massachusetts RFP.

Now -- to deliver 800 megawatts under a PPA.

This has a lease area that could develop up to 3 gigawatts of production.

And we are looking at having 400 megawatts being operational by the end of '21 and the other 400 megawatts by the end of 2022.

We've already filed the construction operation plan with the Bureau of Ocean Energy Management.

And actually, this is the first and the only U.S. offshore wind farm that has applied for the COP to date.

And we expect the receipt of all of our approvals by the early 2020.

Now the U.S. offshore has significant projects as well.

They were continuing to see momentum being gathered.

Kitty Hawk, which has a 2.5-gigawatt lease area, it's 100% owned by AVANGRID and that is offshore North Carolina.

And we also see other opportunities in the northeast for offshore wind.

In Massachusetts, they will be looking for an additional 800 megawatts by 2027.

New York has said they're looking for 2,400 megawatts by 2030 and 800 megawatts will be awarded in 2019.

And then New Jersey is looking for 3,500 megawatts by 2030.

So there's a lot of momentum for offshore wind in the U.S., particularly the northeast corridor where the wind is especially high levels, probably some of the best in the country.

Turning to Page 11, we'll switch over to Networks and look at some of the regulatory highlights relating to the tax reform act.

In all our jurisdictions, the net benefits have been being deferred since January of this year.

In New York, in March, the recommendation of the New York DPS staff was to return all tax savings to the customers through a current rate case or a sur-credit by October 1. We proposed to offset the storm cost and the automated meter infrastructure revenue requirements, some resiliency investments and other deferrals we filed at June 29 to offset that with the tax savings.

And that decision is expected in the fall.

In Maine, we have a stipulation agreement, which approved the increases in the distribution tariffs effective July 1 of this year.

And that includes the recovery of the deferred October '17 storm restoration costs of $44 million, most of that being offset by the Tax Act savings and the existing storm reserve.

In Connecticut, net benefits have been deferred as well, and we have proceedings in process.

We would expect an answer sometime in the fall and the same in Massachusetts.

Under FERC, the New England Transmission Owner formula rate will automatically capture those benefits, and that's really for United Illuminating and Central Maine Power.

And FERC has opened proceedings and is currently just -- is addressing comments.

On Page 12, we have some other regulatory highlights.

In New York, the AMI discussions are ongoing.

We would expect an answer from the commission by year-end.

The Earnings Adjustment Mechanism has been impacted by the storm investigations.

AMI or management audits are now -- that's being pushed, we believe, into 2019.

Connecticut, we filed a rate case for Connecticut Natural Gas on June 29 for rates to be effective by January 1 of 2019.

Berkshire, we filed a rate case in May with rates to be effective in April of 2019.

CMP has been ordered to file a distribution rate case by October 15.

There was a 10-person complaint, which is a process in Maine that allows people to make -- if they get 10 people to sign, they can get a -- file a complaint with the commission.

Commission looked at it and looked at the ROE and said its peers were earning above our allowance so they want us to file a rate case, which we will do and actually that will allow us to also include capital projects for our resiliency program in Maine as well.

So we'll be able to take advantage of that opportunity.

At FERC, really no change in the ROE Complaint IV and really no progress on Complaint I remand or on Complaints II and III at this point.

NECEC update on Page 13.

The transmission project that was selected in the Mass RFP.

It's a -- remind you, a 1,200-megawatt transmission project delivering Canadian hydro.

It's a $950 million investment excluding AFUDC.

We've executed the contracts at the Massachusetts CDCs and Hydro-Québec on June 14 and they were filed yesterday.

It's an escalated price for years 1 through 20 and then a fixed price for years 21 to 40 on the transmission component.

And construction will begin in 2019 and be operational by the end of '22.

And we expect all state permits by the first quarter of '19 and then final approval by year-end '19.

And we really have strong support from the Maine governor and the local community.

All but one of the communities along the path have filed letters of support and those ones that didn't just have said they are supportive, they just haven't filed the letter in support of it at this point.

We're also, on Page 14, are developing a comprehensive and robust networks resiliency plan, and we're calling it Transforming Energy plan for New York and Maine.

It will be a $2.5 billion project over 10 years and includes capital costs of about $2 billion, of which $500 million is really the AMI, which is included in our long-term outlook.

$1.5 billion is not in the long-term outlook.

And then we have operating expenses of about $500 million, which would be for vegetation management primarily.

And really the objective here is to harden the grid and really improve the reliability for customers.

With all the storms we've been having, we believe it's just prudent now to look at what we can do to mitigate the impact of these storm costs that are having and just eliminate the need for the outages that are caused by the storms as much as possible.

So what we're going to do is look at and accelerate a replacement program for our wood poles and using a higher-quality pole in many instances.

We're also going to use tree wire, and this is really coated wire that if there is a contact with a branch, it can resist that from going off-line.

We're going to look at a cost-benefit analysis, some infrastructure hardening, and this is really undergrounding in some areas where we deem it can make a lot of sense.

We're looking at nonwires alternatives such as using battery storage and other techniques to enhance the grid, aerial cable that is more resistant to outages.

And then we're also looking at ground-to-sky tree trimming and identification of hazardous trees, which are outside of right-of-way.

We have done the ground-to-sky in Connecticut for several years now, and it allows us to be able to have less outages.

And we saw that this last year that Connecticut had fewer outages than perhaps we had in New York and in Maine because of the use of this tree wire and the ground-to-sky trimming.

We're also targeting certain distribution circuit upgrades really to improve the grid interconnectivity and alternative sources of supply and really this will allow to facilitate more of the distributed energy resources that are coming onto the system.

And we will be looking at full implementation of advanced metering infrastructure in New York in this time frame.

Also we want to point out that AVANGRID announced an increase in the dividend.

We've raised it from $0.432 a share to $0.44 a share for an annualized rate of $1.76 and that's going to be in the third quarter.

We're still targeting a 65% to 75% payout ratio.

And the dividend will -- should be increased in line with earnings per share growth, again subject to staying within that payout range.

I want to make sure everybody understands our long-term strategy is on track, and we're very optimistic for AVANGRID's future.

When we look at implementing our strengths, we are -- we have signed 158 megawatts for a new contract already.

We have the rate cases, which we're going to be filing, which will help improve our outlook.

And we're still looking at best practices in cost mitigation.

This is an ongoing practice we have across all of our companies to make sure we're getting as efficient as we can in every area.

The RFP awards that we have received for NECEC and the Vineyard Wind partnership make our long-term future -- I mean, really not that long term, in the next 5 years, very attractive.

And we will continue to fulfill our commitment to increase the dividend.

So we are reaffirming our 2018 outlook with earnings per share of $2.16 to $2.46 and adjusted earnings of $2.22 to $2.50.

We are guiding towards the lower half of the range based on the 2 things that I mentioned with the transmission and start-up issues at Tule and El Cabo and then the minor storms, which severely impacted us.

Those 2 together cost us $0.12 a share in the first half of the year.

And we're also reaffirming the 2016 to '20 and 2016 to '22 earnings per share and adjusted earnings per share of 8% to 10%.

So with that, I'm going to turn over to Doug Stuver for his inaugural run at a quarterly earnings call.

Thank you, Jim.

Good morning, everyone, and thank you for joining us today.

I'm now on Slide 18, and we'll go through the business segment details of our second quarter and first half earnings performance.

On this slide, we show our U.S. GAAP roll-forward earnings per share from the second quarter and first half of 2017 to the same periods in 2018.

As Jim mentioned, while we continue to execute on the key objectives of our long-term plan, our second quarter EPS is down 11% versus last year, declining from $0.39 per share to $0.35 per share, and our first half EPS is down 2% from $1.16 per share to $1.13 per share.

Recall that the U.S. GAAP results include the Gas Trading business for the first few months of the year and the Gas Storage business for the first 4 months of the year, including all of the first quarter as well as a loss from the held-for-sale measurement of the Gas Storage and Trading businesses.

U.S. GAAP results also include Renewables mark-to-market, small restructuring charge in the first quarter of 2018 and other items.

On the next slide, Slide 19, we show our adjusted earnings roll-forward, which excludes the gas businesses that we exited this year, the Renewables mark-to-market and the other items.

Adjusted EPS is down 10% from $0.46 for second quarter of 2017 to $0.41 for the second quarter of 2018.

That's primarily due to lower results in the Networks and Corporate segments related primarily to storm impacts, corporate interest and tax impacts.

For the first half of 2018, adjusted EPS was $0.01 per share higher at $1.20 per share than it was for the first half of 2017 as positive performance in the businesses, including the benefit of new rate gears in the Networks business, were offset by storm-related costs and corporate impacts.

The next several slides provide more detail on the business segment impacts.

Moving to Slide 20, you can see our second quarter results for Networks were negatively impacted by storm-related costs.

While costs related to our large storms are deferrable, in addition to large storms, we had multiple minor storms.

The number and severity of storms had secondary financial impacts as well, including, for example, lower capitalized labor as the distribution crews spent a higher portion of their time on storm recovery.

We also had higher overtime expense as our crews completed the storm recovery and caught up on maintenance activities.

In total, these storm-related expenses had a negative after-tax impact of approximately $0.07 per share in the first half.

As we catch up on the distribution CapEx over the remainder of the year, we expect to see higher capitalized labor to help reduce this impact.

Importantly, also as Jim noted, our $2.5 billion resiliency plan proposes to harden our power grid and help minimize the impact of future storms.

For the first half of 2018, we see that the impact of the storms was offset by increases in distribution rates due to the multiyear rate plans in the New York State Electric & Gas, Rochester Gas & Electric, United Illuminating and Southern Connecticut Gas companies.

Those rate increases produced approximately $45 million in additional gross margin during the first half.

Turning to Slide 21.

Our Renewables segment demonstrated quarter-over-quarter and year-over-year earnings improvement.

As Jim mentioned, this was largely driven by the 5 new wind and solar projects totaling 590 megawatts that became operational by the end of 2017.

While positive, the numbers for our new wind projects do reflect the impacts of start-up issues and transmission outages that we had with our El Cabo and Tule wind farms, primarily with the transformer and turbines at El Cabo and the transmission cable at Tule.

As Jim noted earlier, these issues combine for a negative $0.05 per share impact on the first half results.

The issues at Tule, I'm happy to report now, have been resolved, and we've made substantial progress as well with the issues at El Cabo.

As you can see, performance in the second quarter of our existing wind and solar was flat and contributed $0.02 per share in the first half.

While the wind resource for the first quarter of the year was at our average, the second quarter was constrained by below-normal wind results.

Results were also impacted by expiring production tax credits, which reduced the second quarter adjusted EPS by negative $0.03 per share and the first half adjusted EPS by negative $0.05 per share.

In addition, the reduction in federal tax rate and positive year-over-year discrete adjustments resulted in a positive impact in the second quarter of 2018 versus 2017.

The impacts were offset for the first half comparison due to negative year-over-year discrete adjustments.

On Slide 22, we look at the Corporate segment, which was driven primarily by financing costs and taxes.

At the Corporate segment, adjusted EPS was down $0.09 per share for the second quarter of 2018 versus the second quarter of 2017, and the same amount for the first half year-over-year comparison.

The segment results were impacted by higher financing costs with the issuance of our green bond in November 2017 as well as the absence in 2018 of interest income from the gas businesses that we exited earlier this year.

The loss of intercompany interest income from the gas businesses reduced the second quarter results by $0.02 per share and the first half by $0.03 per share.

Taxes negatively impacted Corporate by $0.06 per share in the second quarter and $0.04 per share in the first half of 2018.

That's primarily from consolidating adjustments to balance the segment's income tax results with AVANGRID's consolidated income tax results.

These consolidating adjustments only apply in the quarterly results and will fully reverse by year-end.

The consolidated effective tax rate on adjusted earnings through 6 months was approximately 24.2% on a management reporting basis.

Now turning to Slide 23, we provide additional details for the drivers in the Renewables segment, which I've already largely covered.

Our installed capacity has increased 455 megawatts from the first half of 2017.

We have approximately 497 megawatts under construction with our 10-megawatt solar plant expected to reach commercial operation in 2018 and the other 2 projects expected to reach commercial operation dates in 2019.

As noted, our capacity factor was higher year-over-year with the new additions.

Total capacity factor rose 4% from 32% in the first half of 2017 to 33.1% in the first half of 2018.

The year-over-year improvement reflected a relatively flat impact from our existing wind farms, which increased from 32% to 32.5%.

Our capacity factor for new capacity in 2018 was approximately 37.6%.

Wind production increased year-over-year by 12%.

That's driven primarily in the South/Texas region due to our new capacity and in the West.

While new capacity added approximately 946 gigawatt-hours, to reiterate, the wind resource was below normal as evidenced by total production at our existing fleet, which increased by about 122 gigawatt-hours.

As noted, pricing was slightly lower overall, reflecting the impact of lower PPA prices mitigated by higher merchant prices.

Regionally, average prices were lower in the West, Midcontinent and Texas regions and slightly higher in the Northeast region.

Now turning to Slide 24.

Our financial position remains robust and continues to position us well for opportunities included in our outlook to provide resiliency through unexpected events and support the new exciting opportunities outside of our current outlook.

Our debt level, net of cash, as of June 30 was $5.9 billion.

Our credit metrics remained strong with 2.8x net debt to adjusted EBITDA, 28% net leverage and 31% FFO to debt, and those have improved since the first quarter.

Our credit ratings are very important to us, and we maintain our stable BBB+, Baa1 ratings with the rating agencies.

On the next slide, Slide 25, we demonstrate that we have enhanced our liquidity in the second quarter to support our long-term outlook by increasing our revolving line of credit to $2.5 billion.

With this increase, we're now also in the process of upsizing our commercial paper program, which is currently a $1 billion program, we're upsizing that to $2 billion.

We've also added a new intercompany loan facility in the second quarter with IBERDROLA for $500 million to service an additional liquidity backstop.

You may recall too that we issued our first green bond for $600 million in November of 2017.

We're proud to have also been one of the first companies in the United States to do so as well as to be one of the first to issue a revolving credit facility that links pricing to the achievement of our sustainability initiatives.

As a result, AVANGRID will also benefit financially from our strong commitment to reduce carbon emissions, including our pledge to be carbon neutral by 2035.

Finally, on Slide 26, as Jim mentioned earlier, we're maintaining our consolidated earnings outlook of $2.22 to $2.50 per share on an adjusted basis while guiding to the lower half of the range.

We noted a number of unexpected negative impacts in the first half of 2018, the storm-related impacts that affected us by a negative $0.07 per share and the start-up issues at El Cabo and Tule that were negative $0.05 per share.

These are driving this guidance, but we also want to highlight that we continue to work very diligently to implement our best practices programs and cost mitigation initiatives to mitigate this impact.

We've had many successes year-to-date that we're proud of and we feel will contribute significantly to our long-term performance.

We successfully executed the new contract to grow our Renewables business, reaching 83% of our initial 2020 goals and moving us closer to our 2022 goals.

And we continue to increase earnings in the Networks business through our Forward 2022 best practices initiatives, allowing us to continue to earn our [allowed] returns and into the sharing bands.

As a result, we are reaffirming our 8% to 10% guidance for our 2016 to 2020 and for our 2016 to 2022 periods based on our long-term outlook as of February 20, 2018, Investor Day.

Finally, I'll reiterate that while continuing to implement our existing plan, we'll continue to execute the large industry-leading projects that we have outside of the plan, positioning us for continued growth and value creation.

Thank you, and I'll now hand the call back to our operator, Joelle, for questions.

(Operator Instructions) Our first question comes from Praful Mehta with Citigroup.

So just quickly on the lowering of the guidance, so I guess, to the lower half.

If you do the math, that's probably about what, $0.07 of, I guess, negative impact relative to your midpoint of guidance before.

If you can just bridge us, right, because if you take $0.07 from the Renewables -- from the Networks side, $0.05 from Renewables, that's $0.12.

Are there offsets to that?

And what is the impact of EAM to the guidance that's low -- you kind of noted that, that also impacts your guidance.

So just a little bit more color on kind of the math of how you're getting to that $0.07 impact lower in terms of 2018 guidance.

Well, the 12 -- you're right in the $0.12 has come down.

We're looking at mitigation strategies, which we do all the time.

How do -- what costs can we take out that were in the budget that we're looking at, so we're taking those things into consideration right now, and we believe we can offset some of that.

We're trying to offset as much as we can with other strategies, which are the ones we went through on looking at everything from mitigation to best practices to selling some development projects, which we do pretty much every year.

Now we're going to do that on a continuous basis because we have such a big pipeline of projects.

We want to high-grade it and make sure we're getting the best value out of those.

So if we can get more value by selling them now versus offering, then we just look at it on an internal rate of return and net present value basis to see how -- which ones we can maximize the value for, and we have our team that's working on that directly.

So there are things that we're doing to mitigate it, and that's why we -- it's probably a little less than just the full $0.12 because we do believe we have -- do everything we can to mitigate that.

As far as the EAM, we've never put out a number on that, and we don't really want to at this point because we're still in negotiations with the staff over how much we could get for that EAM.

Jim, if I could add a couple of things on that.

So as I think about the impact of the storms in the first 6 months of this year and Doug touched on this, some of the impacts are not direct costs of minor storms, but they're things like we've fallen behind on our capital spending plan for the year because our crews have been busy working on storm restoration.

So to the extent over the remainder of this year, we can catch up on the shortfall in capital investment, that will allow us to get our capitalized labor number back up to where we anticipated it would be relative to where it is in the first 6 months of the year.

So there are some components of the costs associated with storms in the first half that we do have the ability to try to catch up on.

On the EAMs, I would just say that historically, the New York companies have had an incentive program around energy efficiency that we've earned a few million dollars on year-after-year.

Those ended 2017.

And now given the delays we've seen on EAMs, we really anticipate no opportunity to earn any kind of incentive, whether it's on the old program or the new one for 2018.

So that's why we mentioned it.

But I will say that the vast majority, the largest issue that affected Networks in the first half really surrounds the cost of minor storms and associated impacts.

Got you, that's super helpful color.

And I guess, right, if you've delayed CapEx because the crews are busy, I get that.

But just so I understand on the storm costs, why are some of these nonrecoverable?

Or is there not a regulatory asset that can be created at some point to recover?

Why do they kind of cross the threshold in terms of size, where they are too small there, it kind of...

Yes, I mean, just generally speaking, the way rates are set, and it varies by jurisdiction obviously, but there's a certain amount that you are allowed in rates for minor storms.

And then if a storm reaches a certain threshold, whether it's number of customers affected, percentage of customers in area affected, the length of the outage, things like that, you're able to defer them for future recovery.

And what we saw in the first 6 months in addition to some -- quite frankly, some very large storms, we had a series of many small storms as well as threaten storms where we have to prestage our crews whether the storm occurs or not.

And it's those costs that you really can't defer because there's an assumed amount embedded rates and what we saw is the amount that we incurred was well in excess of what was embedded in rates.

And a lot of those storms just didn't hit the criteria that are required to classify it as a major storm and so they can't defer, which was Bob was saying, so -- and we had many of them.

And little popup storms that affected a number of customers, it could have been 10,000 or 20,000 at a time, that we had to send crews out to work overtime, bring in contractor crews and pay them, but it didn't meet the qualifications for a major storm.

So you just don't expect to have that many, and we had an inordinate amount in the first half of the year.

Our next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.

Wanted to follow up here on the near-term stuff, then also focus on some of the longer-dated guidance updates.

First, can you comment a little bit more on the impacts from the collateral received from the 2 contracts relating to a counterparty bankruptcy?

And more, I just want to make sure if I understand it, rolling into 2019 and onwards, is there an impact we should be aware of or is this truly just kind of awash in '18 alone?

The bankruptcy of the FirstEnergy Solutions' entities and we had contracts where we had collateral that we got paid this year, but we didn't include it in earnings and it will get spread out over the balance of the year.

So that's part of it.

Then into the future, we're going to be selling into the marketplace and PJM basically.

So yes, the contract price was high and it's going to be a lot less now that we're moving and we'll be selling at the market price.

So it has an impact.

Now is it -- it's not huge to us, but it is significant.

So I think you got to -- we got to look at that and we can -- and that's the color for it.

So we're getting, I think we said was it the -- what was the collateral?

I think we deferred.

Yes, we [haven't].

We had $7 million of collateral that was taken to our GAAP earnings in the second quarter.

We've adjusted that out though in our adjusted earnings, so that's only hitting the GAAP results.

You don't want to quantify that yet, year-over-year, like how much the PPA roll-off is?

Not yet, we'll get you something on that in the future perhaps.

But it's -- we usually don't give out those individual contract prices because that is something we usually can't disclose.

So it's -- just know that we have 2 wind farms that we'll be selling in the PJM now, which the prices are actually fairly good, but it's not the same as the old contract prices.

Excellent.

And then also a longer-dated question here both on the utility side and the renewable side.

First, utility.

You talk about a 10-year plan.

About $1.5 billion of capital not yet reflected in your long-term outlook.

How much of that is in the first 5-year outlook as you see it right now?

I just want to understand that a little bit.

And then on the Renewables side, just wanted to come back and understand a little bit where these 2 incremental large projects place you within your long-term earnings guidance range and how you -- when and how you want to reconcile those or roll those in basically?

Well, the first part on the $1.5 billion, I think it's spread reasonably evenly over the 10 years, Julien.

So that's -- you can look at it that way.

The $500 million that's going to be O&M, obviously, we want to have commission approvals to pursue those with -- we can probably use some of it, but a lot of it is just going to be vegetation management, [tree trunks] and so forth on a different basis.

But you really want the commission buying off on those.

The other part of your question was the 2 projects, that you talked about NECEC and then the offshore wind or...

And from what I understand, neither was included in your initial long-term guidance range provided earlier this year.

Right, and it still is not.

That guidance is still as of February 20 of this year, and we have not included it.

We will look in the next time we update, which will be February of '19 as to whether -- what we include in for those 2 projects.

Can you give us maybe a preliminary sense of where that puts you within the range or just kind of some preliminary sense of EPS contribution by '22 from these projects?

Not yet at this time.

We'll get there eventually.

I don't want to update it right now.

Our next question comes from Greg Gordon with Evercore ISI.

You answered several of my questions.

I have a few more.

So I guess, you already answered the question.

I'll try to ask it differently.

In terms of the Massachusetts RFP, the New England Clean Energy, the earnings impact from those projects, I mean, will there be some sort of construction work in progress-related type of earnings stream and when might that kick in and when would they go COD and how does that fit into your long-term earnings guidance?

For the NECEC, we would expect to have AFUDC on the project, and it won't start until we actually start more construction really.

I mean, we're spending a little bit now.

But really it's going to be 2020 when we -- that would start kicking in, Greg, for NECEC and then operational by the end of 2022.

So you're going to have basically 3 years of AFUDC.

And then on the offshore wind, we'll have basically a capitalized interest on those projects starting again probably in about the 2020 time frame because the first 400 megawatts will be operational in '21 and the next 400 in '22.

So that's how I would look at it.

And like I said, we have not included any of it in our long-term plan at this point.

Yes, but I guess, it's sort of a double-edged sword in terms of message today.

Near term, you've got some headwinds from operational issues and the storms.

You've also -- we've also got to now contemplate the sort of mark-to-market on the [FES] wind projects, right?

So near to medium term, there's some issues, but longer term, it seems like the filling in the growth opportunities is going pretty well.

Is that a fair summary?

Yes, I think in long term, yes, we're very optimistic.

The projects we have and even the businesses, the Networks business actually performed very well like, if it weren't for the storms, and Renewables as well, and we had a couple of outages.

So when you see the Renewables, the margin was up actually $64 million from our new projects, and we have a few headwinds from a couple of things that are pretty much gone now.

I mean, the transmission outage -- the internal transmission outage at Tule, which caused us to be off-line for a month.

And then the start-up issues we've had with the turbines are getting resolved and they're actually mostly resolved at this point.

So we're in pretty good shape there.

So going forward, I think things look very good for us, it's just we got a couple of hiccups in...

And how much will -- I mean, within the 8% to 10% sort of earnings guidance outlook, I mean, what's the sort of materiality of the mark-to-market on the FES contracts?

I mean, is it a really big swing inside the range?

Or is it just relative to the size of the overall portfolio or is it not that big?

I wouldn't put much into it.

It's not going to be that material to us.

One of the things I -- oh, go ahead.

Sorry, no, no, please go ahead.

Well, I was just going to say, we just got word that we've been successful, and we're buying a project in development phase in Texas, that's 220 megawatts with a 12-year hedge, fixed-price hedge for us that we just got successfully signed up just now.

So we're adding another 220 megawatts to our secured project list.

Brand new as of your words just spoken right now?

That's great.

Just now, Greg.

[So that's just] 378 for the first half.

Congratulations.

One last question.

You talked about the Maine PUC show cause request act for you to file a rate case as an opportunity but why should we not think about that also as a risk given that they think that you're -- you might be overearning and how material -- what is the sort of -- what's the sort of risk/reward that we're looking at in terms of you're now being compelled to file a case there?

Yes, Greg, this is Bob.

So a little bit of history maybe to start.

So since we reached the prior agreement, our ROEs have generally ranged in the 9% to 11% range with the 11% being in 2017.

And that is based upon our actual equity ratio, which we have kept at a level slightly higher than what was originally put in that last rate case because of the fact that we've been between MPRP and now Lewiston Loop and other projects and now with $1 billion NECEC project, [maybe] we feel it's appropriate that we keep the equity level at that company somewhat higher.

So we've been in the 57, 58 kind of range in the last couple of years.

When the commission looked at it, they looked at it from the perspective of how rates were originally set, which was the 50%, and it produced obviously a higher ROE from that perspective.

As we think about this going forward, there's a number of things, quite frankly, that are even new this year as compared to our '17 results.

We have a new accounting standard on pension, it doesn't allow us to capitalize as much of our pension expense.

We don't have pension deferral mechanism in Maine.

We have higher property taxes.

We have our resiliency plan that we want to get put in place.

So there's a number of things that, while I can't say we would have been necessarily planning to file this year, the fact that we've been ordered to do so, we'll do that and we'll make sure we update because it's been 4 years since our last case for all of -- all of the cost structure.

The one thing, as I'll say again, we will continue to argue though is that in light of the growth that we're seeing at CMP, it really argues for making sure you have a very strong balance sheet.

And so we're going to look to try to maintain that higher equity ratio.

Our next question comes from Michael Lapides with Goldman Sachs.

Just curious, how do you think about the changes in the capital program that you've announced, meaning the energy -- transforming energy plan and obviously, the offshore wind and NECEC?

And how much incremental, if any, balance sheet capacity you have to self-fund these type of growth projects?

For the balance sheet, we have, as you know, very low debt, so we can fund those projects on our -- with our balance sheet now.

I don't know, Bob, do you want to...

Yes -- no, I mean, a couple of things.

Obviously, the resiliency plan is one where, as Jim mentioned earlier, is -- it's really a 10-year plan and a lot of that spending will incur until we get regulatory approval most notably in New York and in Maine.

So that's really a probably like 2020 to 2028 pro rata kind of spend if you would, recognizing that some of it, about $0.5 billion is OpEx, the rest is CapEx.

So again, I think that's something that is over a longer period of time.

The 2 that are more short term in nature because the construction is going to be going concurrently obviously is with NECEC and Vineyard, which are both in that late '19 to 2022 time frame but as Doug and -- had in his discussion and Jim, I mean, we're starting with a 28% debt to capital.

I think that's a pretty good spot to be in and certainly allows us to absorb these projects with the balance sheet we have.

Got it.

And one quick follow-on.

What is it -- and I'm thinking about Vineyard Wind, what is that you think is differentiating your projects from the other projects that have bid into some of these RFPs but maybe didn't win something as kind of scalable or as large in size as your 800-megawatt Vineyard Wind project.

What are you doing differently?

Well, I think on Vineyard Wind, there's a couple of things.

One, clearly, we have the expertise because of our partnership with CIP and the relationship we have with IBERDROLA, we'll have expertise in building offshore wind.

I mean, [offset] those 2, but we also have the onshore wind that we've been doing for a while.

So we have that expertise and also the regulatory that we can deal with in states in the northeast.

The second big thing is by being able to bring the project in, in 2021 and 2022, we get ITC.

And I think others could not get the ITC because as much because they were later.

And so that is probably a big differentiating factor as well.

But as I said, we know people who have done this, who have built these projects.

One of the people that's working directly on this for us is the global head of Offshore Wind for IBERDROLA, and he's partner -- he's overall managing the overall [project] from our perspective.

So having that expertise is something that you just don't get by just doing the small projects here and there.

So I think this is something that's a big plus.

Plus we have the ability to then work with our suppliers to drive down the capital costs and because of IBERDROLA's purchasing power and CIP, put those 2 together, it gives us an advantage as well.

So I think there's a number of things that have put us in a better position than others.

Our next question comes from Steve Fleishman with Wolfe Research.

Just on the renewable development projects and the plan to monetize those.

Can you give a sense of how meaningful that could be as an offset this year and in the future years?

Like how big a part of your plan does this become?

I don't think it's going to be enormous, Steve.

I mean, I think it's going to be fairly small.

But it's one of those we're just going to look at to look at monetizing.

I don't know that I could put a number on it right now.

But we have...

And it's included in your operating earnings?

I assume.

Yes, because these are things that are ongoing.

I mean, we do this constantly.

Now it's more -- we're putting more of a focus on it because of the size of our pipeline.

And we want to make sure that we're high grading it and getting the best projects to the market as quickly as we can.

And those that we think are a little longer term, we may generate more value by selling it to someone who can develop it sooner.

So we have done it in the past, and we're going to continue to do it.

But I wouldn't say it's huge, but it's going to be something.

If we can't generate some capital gain out of it, then it's probably not worth doing.

Our next question comes from Sophie Karp with Guggenheim Securities.

Maybe a real quick on the AMI and the new capital plan that you're rolling out.

So AMI, is that included in that and assuming those are the same that you currently have pending in New York?

Or is that something incremental?

It's the same.

It's what we -- we haven't spent anything on that in New York yet because we've been waiting for the regulatory approval.

Yes, we highlighted only because when we first filed for approval of AMI in New York, it was really a part of a REV proceeding and a DSIP plan to enable our customers to have better visibility into their energy usage and so therefore be able to do through time-of-use rates, both lower their bill and better manage system peaks.

But the reality is, and we've experienced that in Connecticut and in Maine where we have AMI, there's tremendous benefits to the Networks business as well from the standpoint of storm restoration and visibility into the system.

And so we included as a part of resiliency plan just to acknowledge that there are operational benefits as well as customer benefits.

But as Jim said, it's one and the same.

All right.

So there isn't going to be yet another proceed in the deals with AMI?

No, no, no.

Okay, right, that's what I wanted to know.

And on the -- switching gears a little bit on the offshore wind projects, now that you're, as you mentioned, you can bring them online pretty fast, right, versus the other potential bidders.

How are you feeling about being able to obtain all the permits on time for that?

Has that changed maybe since the last time you spoke?

And also what is your time line for key procurement decisions for that, for that project?

Yes.

When you look at it that project's been going since 2015, so we -- I mean, CIP has been working on it since about then.

So the time line to get the permit, we're looking at the end of 2019.

We should have all the ones we need.

I don't know, Laura, you want to comment on that as you're on the phone?

Yes, you bet and thank you.

I would tell you that our permitting plan, both federal and state, is on track according to our program.

And we absolutely appreciate that energy and time of the different agencies that are -- they're putting into progressing these projects, you probably saw the SEIR, the Supplemental Environmental Impact Review that was requested, and we actually are really positive about that.

We saw that as a positive sign that it's being taken seriously.

And I think it also proves that the process is working because it provides an opportunity for people to raise concerns and for developers to respond to those.

So we feel like we are absolutely on track, and we are confident we are going to get there.

And just following up on some of the comments on what differentiates our projects.

I would say it's the local teams.

We actually have had folks on the ground there since 2011, 2012.

And it is a really genuine effort to gain local support and make sure that this project is a win-win.

And when you look at the components of our bid, not only did we -- able to provide a very attractive and competitive price for the consumers, but we're also able to get value for shareholders out of the price because we've done things like focused on local content and local jobs.

We've tried to invest in an accelerator program and really just bring all of the local communities along so that everybody wants us to be successful.

And I think that's what helps us differentiate our projects.

All right.

And then the procurement timing?

We are in the procurement process now.

The way that these large offshore projects are split up, they're put into several big packages.

So you've got the turbine packages, you've got the underground cable packages, you have the substation packages, and so forth.

So we are already [out under] on all of those.

And I anticipate a lot of the decisions will have to come together at the end of this year, early 2019, in order for us to keep on track with our program, which we certainly intend to do.

Got it.

And is that necessary to accomplish that by -- within this time frame to qualify for tax credits?

Or can that procurement slip sort of...

I don't think we want the procurement to slip mainly because to get the tax credit, we need to be -- show commercial operation by the end of 2021.

So we don't want that to slip.

Our next question comes from Angie Storozynski with Macquarie Investment.

So just 2 quick follow-ups.

So the 8% to 10% EPS CAGR for 2020, based on what we know currently, where would you be in that range?

We haven't commented on where we'd be in the range.

Just to say that we will be in the 8% to 10% range for the growth for 2020 and 2022 for that matter.

Okay.

And then on the offshore wind, assuming that there is any delay, a meaningful delay on the regulatory front and that first 400 megawatts does not come online by 2021, is this -- I mean, I'm just trying to gauge how big a delta and the profitability of this project would that -- would the lack of ITC have on that first 400 megawatts.

If -- the ITC would go down, if it comes in, in 2022, let's assume that, right now, the ITC for getting in by 2021, I think, is 24%.

And it would drop to 18% under the legislation if it's a year later.

Okay.

But the -- I mean, we clearly don't actually see that -- the contract yet, but it would not necessarily make this first 400 megawatts unprofitable?

No.

I mean, we're assuming we're going to get it in 2021 to begin with.

So yes.

Our next question comes from Christopher Turnure with JPMorgan.

The only question that I had remaining was on wind resource from both existing projects and new projects.

I know you've run for, I think, a couple of quarters now below your normal expectations and commented that maybe the normal was a bit of a moving target.

Is there any update there and kind of how have you been doing this quarter or year-to-date versus a apples-to-apples normal?

The year-to-date, we were off about 2% from our expectations, from -- which would be our normal.

West and Texas were actually well up and over on the production side.

Midcontinent, which is kind of the MISO area and PJM in the northeast were down.

And Laura, do you want to add anything to that?

No, I mean, I think you've got it and I think we have commented in the past that because of your point that it seems that we've had kind of multiple periods where we've been under our expectation.

We have taken some steps to be more conservative -- our own expectations going forward, so we're hoping that trend will turn around.

Our next question comes from Paul Patterson with Glenrock Associates.

Just on the Corporate side, I notice there's still sort of delta of $0.10, and it sounded to me like the $0.06 associated with the tax was likely to be reversed.

I wanted to make sure if I understood that correctly.

And just how we should think about the next couple quarters and sort of this Corporate impact?

Sure, I'll take that.

This is Doug.

So yes, the item that's affecting Corporate is a consolidating tax adjustment.

That is something that by the end of the year will reverse.

It's basically something that allows the overall AVANGRID tax result to align with the sum of the 2 segments, Renewables and Networks.

We do separate tax calculations at the segment level.

We do a separate tax calculation at the AVANGRID level.

And this Corporate item is something that's used to balance those.

By the end of the year, there won't be a need for any further balancing between the segments and the consolidated results.

So it is something that will go away by year-end.

So that would sort of suggest that, I mean, if I'm just looking at these -- the losses associated with sort of the ongoing numbers, it sounds like there'd be -- I guess, I don't see why you would get close to $0.15 of potential hit from Corporate and other.

Do you follow me?

I mean, when you look at the guidance, it looks a little wide at $0.05 to $0.15 negative for the whole year, and we're now halfway through the year, if you follow me, and you're talking about the $0.06 reversing essentially, correct?

Yes, the impact in Corporate will reverse.

The other thing to add is that the tax rate that we're calculating at the consolidated level is reflective of our expected end result.

So I guess, if you're thinking about taxes from an AVANGRID point of view, really think of it more at the AVANGRID level and not at the Corporate level.

That's more just a balancing factor.

Okay.

I'll follow up later on that, I guess.

Just moving on to Tule and Cabo.

Are those situations completely resolved now?

Do I understand you guys correctly on that?

Tule, it has been.

That was outage of a subterranean transmission line within the property and that's been replaced.

We had a catastrophic failure of that line.

And the start-up issues we've had with the turbines at El Cabo have been mostly fixed.

We're still working on a few things there, but the production's up almost to full, but not quite yet.

But [that's in the result fairly soon].

Okay.

And then just finally on the offshore wind.

Do you guys -- are you guys planning on having firm EPCs for that being built out?

Or how should we think about just -- it's obviously a big sort of offshore deal.

I'm just wondering how should we think about how you guys are -- with your contractors, sort of -- how you're sort of mitigating the potential issue of your cost overruns or something like that.

Yes.

We have -- as Laura was saying, there's like 7 packets for different -- all of the different components of the development of the project.

And each one's got to be looked at separately, whether it's the turbines, the foundations, the transmission lines, the substation, the [ultra] substation.

I mean, there's a whole -- all these different packets and each one's got to be developed separately.

And Laura, do you want to fill in on what you're thinking?

Yes, absolutely.

Just, in general, I would say that in our initial discussions with suppliers, it's been very positive.

I think everybody recognizes that we're not just starting a project here, we're starting an entire industry.

And so everybody is kind of in this together and there's give and take.

And clearly, to the extent that we are able to mitigate risk by putting risk on to suppliers, we'll absolutely work to do that.

But this is a partnership with all these suppliers, and I think we're going to end up in a good spot all together on this.

Our next question comes from Ashar Khan with Verition Fund Management.

Can I just ask, you mentioned the transmission line issue.

You said -- do you know which month it was that it was down?

This was a transmission -- transmission is probably the wrong term.

That was at our facility itself connecting the different wind turbines to our substation.

And that is the line that went down.

It was internal to us and that was in May.

Yes.

So it wasn't an external transmission line.

Okay.

Okay.

And then just -- can I just ask on the El Cabo?

If I remember correctly, we also had some issues in December or I forget in the fourth quarter, you mentioned it hurt you by, I think so $0.03 or $0.04.

So I'm just trying to understand why it's kind of like repeating itself after like nearly 6 months we took some hit, if I'm correct, in fourth quarter of last year and again, now in the second quarter of this year.

I don't know if you could amplify a little bit better?

What was in the fourth -- what was last year was really because the transmission -- this was -- that was a transmission line that was put out of service that would have taken the power from New Mexico into Southern California.

So that caused a transmission outage that went into the fourth -- was in the fourth quarter.

This is -- these are -- the start-up of the turbines not performing to our expectations, I think is the best way to put it.

They're working but not getting the capacity out that we need at the moment.

That's improved dramatically.

And so this has been a process working with Gamesa -- Siemens Gamesa to get these things at their full production capabilities.

Okay.

And then the last question is, can you just talk about, you mentioned the selling on the development side.

So how much can we expect, how many megawatts each year could that be in the range of?

We really don't know at this point and I think we're looking at our entire pipeline as we always do, to see what makes the most sense and what we can get the most value out of by selling or not.

So it could be a range.

So I have no idea what it could be at this point.

(Operator Instructions) I'm not showing any further questions at this time.

I would now like to turn the call back over to Jim Torgerson for closing remarks.

Okay.

Well, thank you, everybody, for participating in the call today.

We are happy that you all can be on this, and we thank you for [talking with us], and we'll talk to you all soon, I'm sure.

Thank you very much.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude today's program, and you may all disconnect.

Everyone, have a great day.