Avangrid Inc (AGR) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2018 AVANGRID Earnings Conference Call.

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

I would now like to introduce your host for today's conference, Ms. Patricia Cosgel, Vice President of Investor and Shareholder Relations.

You may begin.

Thank you, Catherine, and good morning to everyone.

Thank you for joining us to discuss AVANGRID's third 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 on 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 information contained in the slides accompanying today's presentation for definitional information and reconciliations of non-GAAP financial measures to the closest GAAP financial measures.

I will now turn the call over to Jim Torgerson.

Thanks, Patricia, and welcome, everybody.

AVANGRID had a very good quarter and meeting our -- the expectations.

Now GAAP earnings were $125 million or $0.40 a share for the quarter and $476 million or $1.54 a share for the year-to-date through the 9 months.

Now for the adjusted earnings, the quarter had earnings of $139 million or $0.45 a share and adjusted net income of $511 million or $1.65.

When you look at the comparison quarter-over-quarter, earnings per share were up 27%, adjusted earnings were up 11%.

And for the 9 months, the earnings were up 4% and adjusted earnings, up 3%.

And we also had a dividend increase in the third quarter to $0.44 a share.

Now the good thing, we're implementing our strategy, and we are on track to continue implementing the activities we pointed out from our strategic plan.

We have 970 megawatts onshore wind under construction currently.

We filed a rate case for Central Maine Power on October 15, and we also expect to file for the New York companies in the first half of 2019.

The CNG rate case, we have a settlement that's pending before the commission, we would expect an answer in early December.

And the Berkshire Gas case is also in the settlement discussions at this point.

We expect the approval, as I said, for CNG in mid-December.

New rate years for UI, Southern Connecticut Gas, the New York companies occurred during various points in 2018, and we are on track for the 8% to 10% earnings growth and adjusted earnings growth for the period from 2016 to 2020 and then on through 2022 as well.

We're continuing to advance on our large projects, and these are ones that are not in our current forecast.

We're making great progress on the key approvals for Vineyard Wind, and we'll talk about that during the presentation, and this is our offshore wind project.

We have executed the 20-year contracts and filed those with the Massachusetts PUC on August 1. And our NECEC, which is the New England Clean Energy Connect project -- transmission project, we have received the FERC approval and the main certificate of public convenience and necessity is in process, and we're anticipating that in the not-too-distant future.

Turning to Page 6 of our presentation.

You can see the comparison of the GAAP earnings, the 27% quarter-over-quarter and the 4% increase for the year-to-date.

Keep in mind that the GAAP earnings do include the 2 months of Gas Trading and 4 months of Gas Storage business.

They include the Renewables mark-to-market and restructuring and other charges, which are now excluded when we switch over to the adjusted earnings.

And you can see for the quarter, again, moving from $0.40 a share up to $0.45 a share for an 11% increase, and then $1.60 to $1.65 for a 3% increase.

The key drivers for 2018 really are the network rate plans that have been in effect for various periods.

We've had a negative impact in networks from minor storms and lower capitalized labor, and this is one of the reasons we're looking to file a New York rate case, also to incorporate our resiliency plan in New York and Maine as well.

Now -- and we'll talk about that in the upcoming slides.

The new megawatts in production that came in, in late 2017 of 590 megawatts and then the 10 megawatts that started in September this year for solar actually improved our production activities and though it was still somewhat below expectations for the wind resources, and we had a transmission queue that we -- position that we sold this year as well.

For 2018, in the first half, renewable project startups and transmission issues we had have been fixed.

Now I'm going to switch over to Page 7. And as I said, we had a good third quarter.

However, we did not overcome all of the negative aspects in our second quarter, but we are reaffirming our 2018 outlook for earnings per share of $2.16 to $2.46 and adjusted earnings per share of $2.22 to $2.50 at the lower part of the range.

Now guiding to the lower part of the range for '18, there are some impacts that we want to go over.

One is that -- related to the storms, including lower capitalization of overhead, interest and labor and -- versus our forecast.

That affected us by about $0.09 a share.

The delay in the New York Earnings Adjustment Mechanism affected us as well, and then we had startup issues and transmission outages at our new wind farms that have impacted us by about $0.05 a share, and this is all year-to-date.

The low wind production -- the quarter was actually down about 5% from our expectations.

Year-to-date, we're down about 3.2% and that again also impacted us by about $0.05 a share.

And one final item, we're having somewhat higher corporate expenses related to tax and audit.

And this is about $0.02 a share.

And this is additional resources we've taken on to make sure we mitigate the 2017 material weakness to the auditors' expectations and satisfaction, so that's impacting us a little bit this year.

The risks and opportunities, we continue our best practices and operating efficiencies.

Those will continue, and that's an ongoing process for us.

It doesn't stop in any one particular quarter or year.

The wind performance could be up or down and the timing of capital spending.

Right now, Networks is running about $150 million behind at this point.

We should catch up somewhat but not entirely by the end of the year.

And that's having an impact on our capitalized labor and also on our AFUDC.

Weather and storms, hopefully, we don't see any more this year, but we've had an ongoing number of small storms throughout the year.

We're still looking at the sale of renewables development projects as we talked about last quarter.

For those that are in our queue that we may not develop in the near term that -- we can get greater value by selling them off and also looking at the taxes and regulatory.

At this point, we're reaffirming our 2016 to '20 and 2016 to '22 earnings per share and adjusted earnings per share growth of 8% to 10%.

Turning to Page 8, you can see where our -- the renewable projects we have that are under construction and the location: Montague in Oregon; Coyote Ridge in South Dakota; Karankawa 1 and 2 in Texas; and then Patriot Wind, which is a project we purchased in Texas; and then Otter Creek in Illinois.

Those are all under construction with the commercial operations date in 2019.

Just about all of them will be at latter part of 2019, except for Patriot, which will be about midyear.

Turning to Page 9. You can see that we have secured 67% of our 2022 long-term outlook of 2,744 megawatts under PPAs or firm hedges.

We've also secured 94% of our 20-year 2020 target of 1,944 megawatts.

So we are progressing extremely well on the targets we sent out in our long-term plan.

We have 600 megawatts that went commercial operations in either 2017, actually 590 of it in '17 and then 10 megawatts from our solar project this year.

970 megawatts under construction, and then we have an additional 263 megawatts with contracts that will be commercially operated starting in 2020.

So as you can see, 1,833 or 67% of our 2022 target is already secured.

We have 6.6 gigawatts of installed capacity today, and we've increased our onshore pipeline from 8 gigawatts to 9.7 gigawatts.

Just about all of that is solar.

So now we have a total of 13.7 gigawatts in our pipeline, which includes 4 gigawatts of offshore wind.

Moving to Page 10.

I want to talk about our Vineyard Wind project.

That's an 800-megawatt project.

It's going to be the largest U.S. offshore wind project.

Currently, it's a 50-50 partnership with Copenhagen Infrastructure Partners, and we have received -- we won the RFP to develop it in 2 phases.

The first 400 megawatts, which will be operated starting at the end of '21, the price is at $74 a megawatt hour with annual escalations of 2.5%.

The second phase is 400 megawatts at a price of $65 a megawatt hour that also escalates at 2.5% over the 20 years of the project, and that will start in 2022.

Keep in mind that both of these are eligible for investment tax credits and capacity payments.

And the good thing here, we're utilizing existing proven technology in similar locations in Europe that have already been developed by both IBERDROLA and CIP, and the team we have is made up of people from CIP and IBERDROLA.

We're working directly on the project in the project team, along with people from AVANGRID's onshore renewable projects.

This is the idea to be able to get them the -- our people in AVANGRID experienced in building offshore, but we're relying totally on the people from IBERDROLA and CIP to move this forward.

This is the first U.S. offshore wind farm that applied for the Bureau of Ocean Energy Management construction and operation plan, and BOEM's approval time frame allows for the ITC qualification in both '21 and '22.

Now turning to Page 11.

I want to emphasize that Vineyard Wind, with their 800-megawatt project, is on target with our time line and our expectations.

When you look back in the history here, BOEM and the state task force started to look at this and do environmental studies starting in 2009 all the way through 2015.

Vineyard Wind then secured the offshore wind lease from BOEM in 2015.

Now Massachusetts passed their Energy Diversity Act, which required 1,600 megawatts of offshore wind from -- for Massachusetts by 2027.

In May of last year, AVANGRID partnered with CIP to be a partner in Vineyard Wind.

And then Vineyard Wind was rewarded the RFP with the Massachusetts EDCs back in May, and that was the 800 megawatts.

We filed those executed contracts with the Massachusetts Department of Public Utilities in August.

We also filed for the key state and federal approvals in 2017, and we'll go over that with a chart in a second.

The supplemental draft environmental impact report to Massachusetts, that was deemed compliant in September, and now we can submit the final environmental impact report.

The -- we also recently executed a host community agreement in October with the town of Barnstable, and this allows the gen-tie, provides a landing point in Barnstable and also for an onshore substation.

So we have 2 queue positions within ISO-NE going for 800 megawatts each, which will be beneficial for the future.

We signed a lease for the New Bedford Marine Terminal starting in December of 2020.

That's where we'll be offloading the turbines and then using that as a point to take them out into the lease area.

The procurement process is underway, and we would expect the turbine generators to be awarded this fall to a contractor, and then we expect all receipt of all approvals within 2019.

Turning to Page 12.

You can see a little chart of the approvals and the permitting, and they're all on track.

The site assessment plan was filed in March, and it was approved March of '17, and it was approved in May of 2018.

The construction and operation plan was filed in December of '17.

The COP is now considered complete and sufficient, and we will look for the record of decision in the fall of 2019.

It takes about 1 year, once you get the sufficiency -- the completeness and sufficiency review completed, and it's about a year from that to get the record of decision.

So we're perfectly on track to get that done.

The environmental impact study, the notice of intent was in March of '18, the 30-day comment period expired.

The draft will be in the fall, and we should have the final one in the spring of '18 (sic) ['19].

Now for the state approvals, the Massachusetts DPUC approval of contract, they were filed in July, we would expect those in the spring.

We don't see any issues with that with the DPU.

The Environmental Policy Act required notification that was filed in December.

The certificate was issued in February this year.

The environmental impact report, as I said, a supplementary EIR was deemed compliant and the final is now pending.

So the final EIR, we should have in the spring of 2019.

And then we have the Massachusetts Energy Facilities Siting Board, that was filed -- those were filed in December and February of '17 and '18, respectively, and we expect those in the spring of '19.

Now turning to Page 13.

You can see there are significant additional opportunities for offshore wind in the state.

We're looking at the number of them in Massachusetts.

Massachusetts already has legislation requiring 1,600 megawatts by '27 -- 2027.

We've been awarded 800 megawatts.

Another 800 megawatts are expected in 2019.

And then they are looking at another 1,600 megawatts by 2035.

In Connecticut, they have no targets at this point, but they did award 200 megawatts in June of '18.

And in Connecticut, they sent out an RFP, which we responded to, looking for up to 12 terawatt hours of 0 carbon.

We submitted proposals up to 800 megawatts.

In New York, they're looking for 2,400 megawatts by 2030, and we expect them to have an RFP in January for 4,800 megawatts.

Rhode Island is looking for 1,000 megawatts by 2020, and they awarded 400 megawatts in May and another 400 megawatts and an RFP, which has been responded to -- which we are just responding to as of now.

In October, Ryan Zinke, the Secretary of Interior, announced that the BOEM would auction 3 additional offshore leases in Massachusetts.

On December 13, for the lease area of 4.1 gigawatts, 19 companies qualified to participate, including us.

In April of 2018, they also announced that they'd be seeking additional interest in lease areas offshore of New York.

Turning to Page 14.

You can see now our Kitty Hawk project, which we had in, I'll call it, in inventory, and we thought it would be -- at least 10 years away is moving a little quicker now.

We have 100% ownership of these 122,000 acres, which are 24 miles offshore.

The lease area has potential for up to 2.5 gigawatts.

We made -- there's a grid application at Virginia Beach that we have put in for 3 800 megawatts, which was submitted to PJM.

So the project has secured a queue position now for 2.4 gigawatts in the area where demand is expected.

Virginia has issued its '18 -- 2018 energy plan with an objective of getting 2 gigawatts of offshore wind by 2028.

So this time frame is probably moved up where it could be as early as 2025, assuming we're successful in this RFP.

Now I'm going to turn to Page 15 to the networks and look at some of the highlights there.

And this is on -- starting with the tax reform.

NYSEG and RG&E began crediting customers October 1 as required by the PSC order in New York.

And this is really crediting the difference in the tax rate, the difference between the 35% and the 21%.

Maine has included already in distribution tariffs effective July 1, along with the recovery of some deferred October '17 storm costs.

Connecticut, it's still -- the proceedings are in process.

And in Massachusetts, all the Massachusetts utilities were ordered to return the benefits to customers, except those who had rate cases pending, which Berkshire Gas does, and they can -- we had deferred that, and then we'll reflect it in the tariffs once those are approved.

FERC, there -- we -- as you know, we have the New England Transmission Owner formula rate, which automatically will capture those benefits.

NYSEG and RG&E submitted proposed revisions to transmission rates back in May.

Now turning to Page 16.

In Maine, the Maine PUC had an order, recently found that the company acted reasonably in its preparation for and the response to the major windstorm and rainstorm that occurred in October of 2017.

At the same time, they also ordered us to file a rate case by October 15 for a 1-year rev, which we did.

And we demonstrated the need for a revenue increase of $24 million.

In 2017, I think CMP actually overearned.

But going into 2018, it looks like the return is going to be more in line with the allowed returns because we had some issues that are trailing off.

Now we asked for a $24 million rate increase.

However, there won't be any rate impact to customers as we'll use some of the tax reform liabilities, [file] that back to customers so they won't see a rate increase, yet we will get the ability to earn another $24 million in revenue at least.

Now the request includes a 10% ROE and a 55% equity, continue decoupling and we also asked for initially $16 million in capital spending and $5 million in vegetation management increases related to our resiliency program, and we expect to be able to update this during the proceeding.

In Connecticut, the CNG rate case settlement was reached.

It's a 3-year period with a 9.3% ROE and 54% to 55% equity.

It goes -- starts at 54% then moves up to 55% in the third year and also continue decoupling, along -- and also with our DIM program.

We would expect -- the decision would be expected in December.

For Massachusetts, the Berkshire case was filed in May for rates effective April, and where settlement negotiations are ongoing, and this is actually relatively small.

In New York, the AMI and Earnings Adjustment Measurement settlement discussions are ongoing, but they've been delayed because of the storm investigations, the management audit.

We're reengaging now in the fourth quarter.

We also expect to file rate cases by May for both NYSEG and RG&E for electric and gas by May.

Turning to Page 17.

We'll give an update on the FERC ROE.

FERC issued an order on October 16 for the New England TOs, the ROE complaints 1 through 4 and the methodology.

Now the new ROE approach is applied and we'll say preliminarily because it is subject to change, but this applies to complaint #1 and established a range of just and reasonable ROEs of 9.6% to 10.99% and set a just and reasonable base ROE of 10.41%, and the prior ROE was 10.57%.

Now the new ROE cap, including incentives go -- would go up to 13.8% (sic) [13.08%].

Briefs on this new approach are due by December 17, and there could be reply briefs for another 30 days.

But if this goes ahead, as laid out by the commission, we would see a slight benefit to the higher ROE cap versus the lower ROE base.

And you can see from the chart on the bottom, we would have $1,235,000,000 that are actually over the cap, and the cap would be the new base plus the incentives that were granted for various projects.

So 64% of CMPs and UI transmission is currently capped at the 11.74%, and we'd get a benefit by going above that.

Turning to Page 18.

Our New England Clean Energy Connect transmission project, give you a few highlights for this.

The 1,200-megawatt transmission project that would connect Canadian hydro-power to Massachusetts EDCs.

It's a $950 million capital cost.

Timing and approval for the process are really on -- right on track with our expectations.

We expect to begin construction in late '19 and go operational by the end of '22.

We already control 100% of the right of way, 2/3 are on existing transmission corridors and 1/3 are in industrial forests.

We expect all the state permits by the first quarter of '19 and final project approval by the end of '19.

Now turning to Page 19.

I want to go through some of the history here.

We secured all of the rights starting -- we went back to 2015 and up through really the end of 2017 to make sure we have the -- all the rights of way to the Canadian border well in advance of this project even applying or responding to the RFP.

Now Section 83D of the -- in Massachusetts Act required 9,450,000 megawatt hours of clean energy by 2027.

We received support for our transmission project from about 90% of the host communities.

We filed all the key approvals in 2017 and '18, and NECEC was awarded the RFP with the Massachusetts EDCs in March of '18.

We filed those contracts with the Massachusetts Department in July.

We announced an MOU for investment in the Western Maine conservation and nature-based tourism infrastructure with a nonprofit group, the Western Mountains and Rivers Corporation in May of 2018.

And this was in relationship to the going over the Kennebec River.

And you'll see that we announced the other day that we will actually now tunnel under the Kennebec River, and we're going to be filing amendments with the DEP for that application.

And Massachusetts also had a procedural order.

The contracts now are expected to be approved by the second quarter of '19, and this just puts it in context with the time frame we expected all along.

We received our FERC approval October of this year, several months ahead of what our schedule was.

The Maine CPCN is in process.

Public meetings and hearings are already underway, and the examiner's report is scheduled for early December.

So we expect receipt of all project approvals by the year-end 2019, and the procurement is progressing on the converter stations, all the other key equipment, with our economic target.

Turning to Page 20.

You can see where we're on track.

The Massachusetts PUC approval of contracts we expect that, as I said, by mid-2019.

The FERC approval came in, in October early.

The Maine Certificate of Public Convenience and Necessity is on track.

We would expect that in early 2019.

The Maine DEP approval is going to be in the early to mid of 2019.

And then the presidential permit, we should have by the end of '19.

Now that's predicated on the ISO-New England System Impact Study that has to come first.

That study was started on time in August, and we expect completion by mid to end of 2019.

The Army Corps, again, we need environmental assessment from them.

That was filed in September of 2017, and we should have that by mid-2019.

And then local and municipal construction approvals will be timed as needed throughout the project.

Turning to Page 21, our Networks Resiliency Program.

This is a comprehensive plan to address the impacts of storms we've seen not only in New York but also in Maine.

We have capital costs, we're looking at about $2 billion, and only $500 million is in the long-term outlook for the advanced metering infrastructure.

And we also are going to be requesting operating expenses of about $500 million for increased vegetation management.

And these are things where we can do ground-to-sky clearing, we would call it, that would allow better maintenance of the distribution lines so that we don't -- they aren't as impacted by storms.

Some of the other things we're doing would be putting in tree wire, replacing poles, undergrounding where it's deemed appropriate.

So this is a very comprehensive program to limit and mitigate the impacts from minor and major storms for that matter.

This is all subject to regulatory approval, and it will be a program up to about 10 years.

The initial amounts included in the main CMP case, we expect to really update that as the proceeding goes along.

And we will include it in the rate filing in New York in the first half of '19.

And we're already seeing some support from local communities in New York for this type of a program.

So we're on target to meet the expectations.

We're implementing our strategies.

We're advancing our key projects that were awarded RFPs that are not in our long-term plan, and we're already fulfilling our commitments to increase the dividend.

So we are reaffirming our 2018 earnings per share outlook of $2.16 to $2.46 and the adjusted earnings of $2.22 to $2.50 a share, guiding the adjusted earnings per share to the lower part of the range for 2018.

And with that, I'm going to turn over to Doug Stuver, who's going to go over the financial results.

Thank you, Jim.

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

I'm now on Slide 24, which covers the business segment details of our third quarter and first 9 months earning performance.

On this slide, we roll forward earnings per share from the third quarter and first 9 months of 2017 to the same periods in 2018 on a U.S. GAAP basis.

We had a solid third quarter with an increase in our EPS of 27% versus last year, improving from $0.32 per share to $0.40 per share.

For the first 9 months of 2018, our earnings per share increased from $1.48 to $1.54 or 4%.

The U.S. GAAP results include the Gas Storage and Trading businesses, which had negative earnings results in 2017.

With their sale earlier in the year, these businesses showed positive performance in the year-over-year comparisons.

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

On Slide 25, we show our adjusted earnings roll forward, which excludes the Gas businesses that we exited this year, the Renewables mark-to-market and other items.

In the third quarter, we recognized into adjusted earnings the income from collateral related to the FirstEnergy Solutions bankruptcy, which is a $0.02 positive impact for the quarter.

Recall that in the second quarter, we removed this $0.02 impact from adjusted earnings, noting at the time that we would bring it into earnings over the remainder of this year.

This third quarter entry completes the amortization and brings our GAAP and adjusted earnings into alignment for the 9-month period.

Moving to the charts on this slide.

You can see that adjusted EPS improved year-over-year when comparing the third quarter and 9-month results.

For the third quarter, adjusted EPS increased by $0.05 from $0.40 per share to $0.45 per share or 11%.

The third quarter year-over-year comparison benefited significantly from rate increases in the Networks business, although offset by lower capitalized labor and higher depreciation.

Operational results in the Renewables business were also positive for the third quarter of 2018 compared to last year, although it's important to note that the third quarter historically has been the weakest of the year in terms of wind production.

Corporate improvements were primarily related to tax impacts, which I will discuss when we review the Corporate segment.

For the first 9 months of 2018, adjusted EPS was $0.05 per share higher at $1.65 per share compared to $1.60 per share for the 9 months ended 2017, and that's largely due to similar drivers.

For Networks, the new rates in effect in 2018 versus 2017 were a positive driver, but the impact was reduced by minor storms and related impacts in 2018.

For Renewables, the 590 megawatts that reached commercial operation at the end of 2017 contributed positively to the 9 months year-over-year performance, although reduced by the startup and transmission issues that we described in the second quarter.

The Corporate segment for this period was negative due to the new debt issued at AVANGRID in November 2017 and the absence of intercompany interest income that Corporate was receiving in 2017 for the Gas businesses that were sold earlier this year.

In the next several slides, we'll provide more detail on those business segment impacts.

On Slide 26, this summarizes the results and business drivers for Networks.

For the third quarter, you can see that results were down quarter-over-quarter by $0.03 or 9% and up marginally by $0.01 or 1% for the 9-month period year-over-year.

This is despite the benefit of higher revenues from rate increases at our New York utilities with their third rate year beginning on May 1, the second calendar year of the UI rate increase and the first calendar year of the SCG rate increase.

The positive rate increases added $0.06 per share to the third quarter year-over-year comparison and $0.17 to the 9-month year-over-year comparison.

The lower results for the quarter are primarily due to minor storms and related costs and lower capital spending these from events that translate into lower capitalized labor and AFUDC.

For the first 9 months of 2018, we're reporting a negative $0.10 per share year-over-year impact from minor storms, capitalized labor and related impacts.

The minor storm component of this principally accumulated through the end of the second quarter with a negative $0.03 third quarter year-over-year impact mainly due to lower capitalized labor and AFUDC impacts.

And then importantly, as Jim noted earlier, our $2.5 billion resiliency plan will harden our power grid and help minimize the impact of these future storms.

Other impacts that reduced the benefit of the higher rates included higher depreciation and provisions due to new investment, higher bad debt due to a colder winter and the shift from Corporate to Networks for the New York state tax.

Historically, this item, which represents approximately a negative $0.01 per share, was reported in Corporate.

For the 9 months year-over-year comparison, there is a positive impact related to earnings sharing, which is the result of earnings sharing recognized in 2017.

Turning to Slide 27.

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

Performance for the third quarter showed a $0.05 per share year-over-year improvement with earnings from our new resources relatively flat, including only minimal impact from new resources in 2017, and that was mainly our production from the El Cabo facility.

Earnings from our existing resources are up $0.06 per share.

The relatively flat earnings impact in the third quarter from new resources is due to the seasonal pattern of the wind resource production, as I mentioned earlier, that the third quarter generally is the lowest compared to other quarters.

Earnings from our existing resources improved $0.06 per share benefiting from improved wind in some of the regions where we had higher-price PPAs such as in the Western and Southern Texas regions.

In addition, the existing wind and solar results include an $8 million third quarter 2018 earnings benefit from the sale of one of our FirstEnergy Solutions bankruptcy claims.

There, we took the opportunity to monetize this claim and remove any uncertainty of future changes in value.

Both of our wind farms affected by the FirstEnergy Solutions bankruptcy are now selling into the merchant market.

And in the third quarter, there was about $1 million lower result based on the difference between the former PPA prices and the now merchant prices that we use to sell into that market.

The performance of our first 9 months year-over-year was positive $0.11 per share, reflecting the same impacts.

In addition, the numbers for our new wind projects include a negative $0.05 per share impact for transmission issues that we had with our El Cabo and Tule wind farms in the second quarter.

Just as a reminder, those were the transformer and turbine issues that El Cabo and a transmission cable failure at Tule and all of those have now been resolved.

Wind performance was positive year-over-year, but it was lower than our expectations by approximately 3% or $0.05 per share for the first 9 months of the year.

As we noted last quarter, we're continuing to look for value-added opportunities to optimize our pipeline, including the sale of assets in the development stage.

And in the third quarter, we sold a transmission queue position that added about $4 million in after-tax earnings or about $0.01 per share.

Results were also impacted by production tax credits.

We added a significant number of new production tax credits with our new plants that was approximately $0.01 per share in the third quarter and $0.10 per share for the first 9 months comparison.

And then net of production tax credits that are rolling off, the impact was a minus $0.02 quarter-over-quarter and plus $0.01 for the first 9 months year-over-year.

Finally, our taxes and other category includes the impact of year-over-year variances and discrete items and the third quarter recovery of bad debt and curtailment revenues owed by a third party for about $10 million or approximately $0.03 per share.

Turning to Slide 28.

We take a look at the Corporate segment that's primarily driven by financing costs and taxes.

At the Corporate segment, adjusted EPS was higher by $0.03 per share for the third quarter versus the prior year and was lower $0.06 per share for the first 9 months of 2018 compared to the prior year.

Those results were impacted by taxes in the third quarter from primarily a favorable consolidating tax rate adjustment.

This consolidating tax rate adjustment is done to align the Renewables and Networks income taxes with the consolidated AVANGRID income tax result.

So Corporate is basically a balancing item in that process.

In addition, the Corporate segment results reflect higher financing costs with the issuance of our green bond in November of 2017.

That item was minus $0.01 per share for the third quarter and minus $0.03 per share for the first 9 months.

While Corporate had additional intercompany interest income from Renewables, this was offset by the absence in 2018 of interest income from the gas businesses that we exited earlier this year.

So the consolidated tax rate through 9 months was approximately 27.7% on a management reporting basis, and we're forecasting 26% for the full 2018 calendar year.

On the next slide, Slide 29, we provide some details for the Renewables segment, and I've already largely covered those.

I'll just hit some of the highlights there.

Our installed capacity increased 456 megawatts.

That includes the 10-megawatt WyEast solar project that reached commercial operation in September.

And then as Jim highlighted, we have almost 1 gigawatt under construction presently.

Our capacity factor increased year-over-year with the new additions, and we have a 13% increase in production at our wind farms primarily in the South Texas region and in the West.

Pricing was slightly higher overall, reflecting the impact of higher PPA prices and higher merchant prices.

Regionally, the prices were lower in the West, Mid-Continent and Northeast regions in significantly higher in the Texas region, where we have a number of our merchant projects.

Finally, as we're progressing on repowering the 122 megawatts of projects that we previously announced.

We expect to accelerate depreciation commencing in the fourth quarter.

This represents approximately a negative $0.01 per share impact per quarter on our GAAP earnings.

However, we'll be excluding that from our adjusted net income.

Moving to Slide 30.

We continue to demonstrate a strong financial position, which is very distinctive in our industry.

We have a very robust balance sheet, and our cash flow provides us with flexibility to effectively fund our organic growth plans, including the projects in our current long-term outlook.

Along with the exciting investment opportunities we have with our NECEC transmission line and the Vineyard Wind partnership for offshore wind along with the key resiliency enhancement investment program that Jim spoke about.

Our net debt level, that's net of cash as of September 30, was $6.2 billion, and our credit metrics are very strong.

We have 2.9x net debt to adjusted EBITDA, 29% net leverage and 29% FFO to debt.

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

We also highlight on this slide our dividends and dividend policy.

You might recall, last quarter, we announced an increase in the quarterly dividend that went from $0.432 per share to $0.44 per share and that began in the third quarter, and we made that payment on October 1. We retain our target payout ratio of 65% to 75%, and we expect future increases of the dividend to be in line with our EPS growth, subject to this target payout range.

Finally, on Slide 31, as Jim mentioned earlier, we're maintaining our consolidated earnings outlook of $2.22 to $2.50 per share.

However, we're guiding to the lower part of the range due to the unexpected negative impacts related to the unusual storm pattern that we talked about in the second quarter, and that includes impact on our capital spending that resulted in lower capitalized labor cost.

So that piece continued into the third quarter.

And then we have the delay in the expected receipt of any Earnings Adjustment Mechanism, along with lower winds than our normal expectations and then the startup issues that we talked about with the 2 wind projects earlier this year.

We've also adjusted the Networks and Corporate business segment ranges to reflect our updated expectations for 2018.

For Networks, we revised the range down by $0.10 due to the impact of storms and related costs.

We've increased the Corporate segment by $0.09, and that reflects the 9-month result through September that are above our original guidance along with positive potential impact from the fourth quarter from true-ups of our tax provision and deferred taxes to our tax return.

In conclusion, I want to emphasize the many successes we've had this year, including our Renewables PPAs, the 1 gigawatts of projects under construction, ongoing implementation of our best practice initiatives and implementation of new rates from our multiyear rate plans, those position us very well to achieve our long-term goals.

Finally, while we continue to focus on implementing our existing plan, we also have the opportunities with NECEC and offshore wind projects that Jim talked about earlier, which are very exciting, and those are outside our plan, and that position us very well for future growth.

Thank you, everyone, and now I'll turn the call back over to Catherine for any questions.

(Operator Instructions) And our first question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.

Can you hear?

Yes, barely.

Can you hear me now?

Yes, that's good, Julien.

Sorry, I was on mute there.

I apologize.

I repeat.

Sorry about that.

So with respect to the Corporate and other segment and where you're tracking year-to-date, can you give us a little bit of a sense on how you're thinking about fourth quarter?

And how you're thinking about that going forward right?

You have guidance out there in '22 of $0.30 drag.

Obviously, now you're tracking towards more of a flattish or breakeven Corporate and other segment.

How are you thinking about it at this point in time, sort of that the cadence of Corporate and other into future years, if you can elaborate?

Yes, right now, Julien, we're still going to have the interest expense from the Corporate debt we hold.

But we are looking at some tax benefits that we should be deriving in the fourth quarter.

I don't know, Doug, you want to expand on that any?

Yes, I can just add.

In the fourth quarter, that's when we complete the filing of our tax returns and true-up our tax provision and deferred tax amounts to those tax returns.

You may recall last year, we had a fairly favorable outcome in the fourth quarter related to that.

And any impacts or substantial portion of those impacts would fall to the Corporate segment.

So we're in the early stages of that process presently, but directionally, it looks like those could be a positive.

How do you think about the cadence of kind of working up to that $0.30 drag if by '22 relative to where you stand today?

I mean -- or maybe said differently, how do you think about some of the benefits that you're seeing in Corporate and other this year, year-to-date and otherwise reflected in 4Q persisting in the future years?

Well, I think as we move into the future years, we're going to still have -- incurring more debt going out into the next few years to really fund the Renewable business because we do all the debt -- or capital raising at the utilities for the Networks business.

We do make an intercompany charge through some of this debt, but you'll see that, and we get the benefit of that coming back in.

And then the tax benefits do accrue at the Corporate level.

So I would see that you're going to see more -- going forward, more debt there and more interest expense being loaded at the Corporate level.

Doug, anything else?

Do you -- because really there's nothing else there.

I mean, you got some minor charges like board cost and those types of things, but those are pretty small relative to what's in anything else so.

No.

I think that's right, Jim.

We're at 29% debt as of the end of the third quarter, and we project out to '22 -- 2022 to get to 43% debt.

So certainly, there will be increase over time affecting the Corporate results.

Got it.

So it sounds like the only real changes going forward are going to be the incremental addition in debt.

So you can kind of back out of that $0.30 that you project to kind of back into what a structural Corporate and other might otherwise be?

That should be pretty much it, Julien, because the $0.30 you're talking about is on 2022 that we had a projection for Corporate.

Yes, yes, and we're going to be updating our long-term plan when we come to the year-end results, so in February.

Got it, okay.

And then turning back to Maine, if you can.

I know you provided some good detail there already, but I wanted to come back to this.

Just in terms of the time line here for the CPCN you talked about early '19.

How much confidence do you have that you could get that done perhaps in this year versus early next year?

And how much does the changeover in the administration matter to you all just in terms of efficiently getting it done?

Yes, the CPCN, we, we're in discussions now.

And the governor has been very -- LePage has been very supportive.

And the new governor and whoever that's going to be, it's kind of a close race right now, we'll see.

We'll talk to them obviously.

We would expect in the end, there'll be if not neutral hopefully supportive of it.

But -- so I don't know Bob, you may want to fill them in a little bit on...

Yes, I mean, we've been working, as Jim said, Julien, on settlement negotiations with various parties in the CPCN.

As you saw from our disclosure here in the report, there's hearings going on as we speak.

We expect to, really December, to be in front of the PUC in Maine.

So to the extent over the next, let's say, 30 days are successful in achieving some kind of a settlement, I think we've got a pretty good chance of getting it done this year or at worst case very early into calendar year '19.

So things are progressing well there.

The 2 key candidates for the governor's position in Maine have both been, at this point, noncommittal on the project.

They're not for it, they're not against it.

They have said they want to really understand the project and the benefits of it and associated with or in comparison, I should say, to the environmental issues associated with it.

So that's something that we'll do, but obviously, it's not something you can do here in the middle of election process.

So we're prepared to sit down with them in earnest as soon as the elections are over and go through that to make sure that they're comfortable with the project.

Our next question comes from Greg Gordon with Evercore ISI.

Sorry to beat a dead horse and restate Julien's question.

But to be more specific on the -- it may sound pedantic, but to be more specific on the Corporate, in the outlook, you did reduce the midpoint of the assumed Corporate drag for the business for fiscal year '18 from $0.10 a share to $0.05 a share, and that was an offset to the reduction in some of the -- to some of the headwinds that you were seeing.

And I guess, is that -- to put it bluntly, is that just like sort of a structural improvement?

Or are you seeing some temporary or temporal tax benefits that we shouldn't assume are reducing the runway -- run rate in perpetuity?

Yes, I think the long-term outlook is still representative for the reasons we talked about earlier.

We improved the guidance for this year because of where we sit presently, we're actually ahead of the previous range of our guidance.

And we do see potential further upside in the fourth quarter that made us comfortable with that reset.

Yes, and Greg, I don't think it's a structural change more as it is something we see for the upcoming quarter with the tax situation.

And we have enough information that says that it looks like it would be a little bit more positive as far as the tax situation goes that we made that with, but I wouldn't see it as structural because the long-term outlook is reflective of our -- the debt we're going to be issuing for the next few years.

Okay, that's very clear.

And then as we think about the things that are or have been headwinds for 2018, many of them appear to be also sort of temporal problems with startup of certain assets, weather delays and recovering those costs, et cetera.

So while there might be sort of a negative adjustment on the Corporate overheads, we should assume that most of those issues that had caused a delay in revenues or increase in cost this year were also temporal and should reverse next year?

Is that fair or unfair?

Yes, the ones at Renewables, the transmission -- the outage we had at Tule, and then the startup issues we had both transmission and with the turbines themselves at El Cabo are behind us.

I mean those have been rectified, so no issue going forward.

On the Networks side, with the storms, lower -- we can't predict if there's going to be more minor storms, however, what we are going to do to protect our downside is to make filings with the commission in New York and Maine to try to get more into being able to recover some of these minor storms.

I don't know Bob, you want to talk about what's going on there?

Because we can't predict what's going to happen with storms.

Yes, I think there's a couple of -- and you're right, Jim.

And I have to tell you, I think the team has done a phenomenal job this year, but I've never seen a year like we've experienced this year.

Not only in terms of major storms, which are largely deferrable but put a strain on the system in terms of resources.

But then the numerous minor storms, which, as Jim said in many instances, are not deferrable and recoverable, and we have to eat.

So a couple of ways to -- that we're looking to tackle this, one, obviously is the resiliency plan is really important.

When we look at the nature of the outages that we have seen over the past year-or-so, the vast majority are due to tree-related contact.

So that's why a big portion of the resiliency plan that we've announced is focused on vegetation management.

NYSEG, for example, is the only utility in New York State or and the only utility within AVANGRID that is not on a 5-year cycle trim, which is considered standard kind of best-in-class practice.

And it's because NYSEG's service territory is so spread out, it's very expensive, and so it's been difficult we've not been able to get the full cost of 5-year cycle in rates to date.

But this is a big area of focus for us because tree -- again tree-related outages is the biggest topic.

But the other is, quite frankly, is so what else can we do to make the system more resilient.

And Jim touched upon the other areas within the plan that we're focused on whether it's tree wire, it's poles, it's adding redundancy to circuits, selective, I'll emphasize selective underground but things that we can do to enhance the resiliency of the network.

And I can't go without saying also the AMI plays a huge role in that both in terms of visibility for us as a company as we look to restore power but also the benefits that consumers see from that.

And we touched on in the presentation but in our meetings with local municipal leaders throughout New York, there's a growing understanding of how technology can help improve our performance, and they're willing to support us and write letters of support to folks in Albany with regards to investments that need to get made and the trimming that needs to get made to enhance resiliency.

So it's a long way of saying we've got to tackle it through investment and network, and we have to tackle it through better vegetation management.

And so that's going to be a big part of the rate proceedings both in Maine and in New York.

Greg, to answer your question, we see this a lot of the activity this year as being incidental one-offs that occurred.

And hopefully, we don't have all those storms next year, but that was really what was driving much of...

We can't predict that.

We don't know that though.

Great.

And then as you pointed out on Slide 8, it's not going to be a big year for incremental production from new Renewables because most of those plants come online in late '19.

So -- but there should be a significant uptick in production in 2020 from that, correct?

That is correct, yes.

Absolutely.

Those all have PPAs or hedges, yes.

Our next question comes from Christopher Turnure with JPMorgan.

Jim and Doug, a couple of my questions have been answered already, but I wanted to ask about your intercompany loan that you mentioned, I guess, between Renewables and Corporate.

Can you just walk us through exactly what is booked where and confirm that on a consolidated basis there is no impact whatsoever on adjusted EPS?

Yes.

On your last point, that all does eliminate in consolidation, so there is no net impact.

Our general approach for intercompany advances to Renewables is that Renewables will borrow to help finance their construction efforts.

Once the construction is completed, we will tend to then essentially convert those borrowings into equity so there will be an equity infusion into Renewables, and so use that equity to pay off the short-term borrowings.

So essentially, for operating projects, think of that in Renewables as largely equity finance and for construction projects as debt finance, but all of it's intercompany and all of it eliminates in consolidation.

Okay.

And then in terms of any actual external debt to finance the Renewable projects, I guess, at Corporate, when would that occur?

We have, in terms of additional financing activity, we have some slated for the fourth quarter of this year.

That's in the Networks business.

No further financing plan this year at the Corporate level or to finance further Renewables activities.

Okay.

And then certainly, there's some movement on the tax front between different segments, and you guys talked clearly about what we could expect in the fourth quarter there from your tax efforts.

But can you give us a kind of 2018 consolidated tax rate ex the PTC impact and speak to that a bit maybe compare it to 2017 as well?

Yes, I don't know that I can do it right now with the ex-PTC impact.

We have, through the third quarter, in our management format a 27.7% effective tax rate, that includes some discrete items.

And those are largely items that are removed from our adjusted earnings.

And then for the full year, we're at 26% as our forecast.

I apologize, I don't have the 2017 comparison for that, but I think we could probably get that for you after the call.

Okay.

So your forecast for 2018 on a consolidated basis adjusted for any unusual items is about 26% tax?

The 26% includes those discrete items, so things that are somewhat nonrecurring.

Yes, that is the full year forecast.

Our next question comes from Angie Storozynski with Macquarie.

Just one clarification.

So if I look at your slides from the second quarter and the third quarter call, I see that you changed your wording around the guidance for '18.

In the second quarter slides, you said that guidance you're guiding towards the lower half, and now you're saying lower part.

Is this just -- I mean, is there any actually difference here?

Or is this just completely inconsequential word in that part statement?

I think it's a slight difference in that lower half was kind of a broader range, and we were trying to get people to think about the lower part of the range.

So not just -- but it's not that significant of a difference, but it is slightly different, I guess, is the best way to put it.

But is it that it's supposed to imply that it's a lower number versus what you had expected in -- at the second quarter call?

No, not necessarily lower than what we had expected in the second quarter.

Okay, okay.

And one more question, so thanks for all of the details about your offshore wind project.

Can you give us a sense when we will have some additional announcements regarding procurement of turbines, any types of EPC contracts, anything to that effect?

Yes, Laura Beane is on the line.

So maybe Laura, you want to address that?

Yes, certainly.

Good morning.

We will -- we are definitely making progress on all of the large packages for the tenders.

Now we expect to be able to finalize the turbine piece, which is, of course, one of the most important components here in the coming weeks.

And then in the fourth quarter I think you'll see the majority of the large packages starting to come together, and we should be able to, in our February call, be able to make some more specific announcements at that time.

Our next question comes from Michael Lapides with Goldman Sachs.

Just want to ask, when you give out multiyear guidance out to 2020 and out to 2022, what are you assuming as the outcomes for the rate cases in Maine, and more importantly, maybe in New York and the outcome, specifically for your significant distribution investment programs that you announced a number of months ago?

I think we haven't updated anything from -- for these current rate basis.

What I would say is we would anticipate that the ROEs, so to speak, will be in this similar ballpark from where they are today, and we still have the goal of earning into the sharing ranges for all of these.

Now keep in mind, CMP does not have sharing, but that's kind of where we're looking at.

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

Yes, no, exactly right.

I mean, we don't -- Michael, we don't make any kind of significant bets on where we think ROEs are going.

We look at the ROEs we've been granted in the past, assuming a similar structure going forward.

Here's really based upon rate base growth, here's what we can achieve.

To Jim's point, the last long-term outlook we provided obviously was in February, so it doesn't include NECEC, it doesn't include the resiliency plan.

Those will be key aspects of those filings that we have just made in Maine and will make in New York, and we'll incorporate that within those filings.

Got it, okay.

I mean, is there -- I know you haven't updated anything.

So your guidance out to '20 and '22 doesn't include the distribution programs you've announced since the January date, but also didn't even have a base case assumption or some kind of output tied to the rate case outcomes at all?

You have to assume -- first of all, on the investment, the only thing I'll just clarify, remember the resiliency plan that we talked about, it's $2.5 billion, you have a $0.5 billion that's vegetation management, so that's really earnings neutral.

The other $2 billion, $0.5 billion of that is AMI, which was included in our previous forecast.

So the incremental piece to this would be roughly $1.5 billion of investment, and then you have NECEC, okay?

But again, on the ROEs, we look at it I think very realistically to say here's what we -- let's use CMP, for example.

The last case -- the last time we increased rates at CMP was in 2014, and it was a 9.45% ROE and a 50% equity ratio.

So while we filed just now a few weeks ago for, I think, 10% and 54%, 55% equity of the higher equity ratio looking to capture the impact of tax reform and lower cash flows.

As we've developed a long-term forecast, we'll use a more realistic expectation of what we think we'll really get.

Our next question comes from Steve Fleishman with Wolfe Research.

Couple quick questions.

The -- I might have missed this just you mentioned something about accelerating depreciation on one of your projects.

Could you just repeat that?

Yes, so that is with our repowering investment.

We are replacing the nacelle component of our wind turbines.

And we treat that nacelle component as a separate asset class.

So the fact that we'll be replacing that, we end up accelerating depreciation on that for accounting purposes so that by the time the nacelle is replaced, it has 0 net book value or essentially the salvage value.

So my comment was that starting in the fourth quarter, we'll be initiating that accelerated depreciation for the repowered assets, and that is about a $0.01 per share negative impact on GAAP earnings.

We will be adjusting that out for our adjusted earnings, so it won't have an effect on it.

And that's $0.01 per quarter?

Yes.

And then it's gone when, if it's over?

Yes, so the repowering and maybe Laura can speak to the timing of the repowering.

Yes, absolutely.

So we are doing this as a onetime program essentially.

If you recall we did safe harbor equipment for the purpose of repower.

We have just a few assets that we're planning to repower.

We want to make sure that we can safely qualify for the PTC, and we also just want to make sure that we're being prudent in terms of the age of the assets.

Most of our fleet is relatively new.

And so we really don't have a lot of options in terms of how many assets make sense to repower at this point in time.

So the assets all will be repowered in 2019 and 2020, so relatively short time period and by the end of 2020 all of those will be complete.

Okay, great.

And then on the New York rate case filing next year, if you go back, I think, I don't know, maybe 6, 9 months ago, I think you were talking about potentially not filing in New York for future case.

Could you explain why you're going to file now?

Yes, Steve, one -- 2 reasons.

One, to do something about the minor storms to see if we can get that reflected more in rates.

And secondly, with the resiliency plan to be able to capture that.

Also when you look at the Earnings Adjustment Mechanism and AMI, we have filings in front of the commission, and -- but they haven't acted on them yet.

And if they don't by the time we file, we'll just incorporate that into the rate plan too.

So I don't know, Bob, anything else?

No, that's exactly right.

It's really driven by the resiliency plan of what we've experienced this year in terms of the numerous minor storms as well as major storms that we'll look to get recovery from in terms of the costs that have been deferred.

Our next question comes from Sophie Karp with Guggenheim.

Most of my questions have been answered, but maybe if I can just double check on a couple of items here.

First of all, in your utilities, in your networks' new outlook, how much of an impact is there from the new allocation of state taxes?

That was only $0.01, that reallocation for the New York State tax item.

Right, so that's for the -- for 2018?

For the full year?

Yes.

In going forward, how should we think about that?

I think similarly, New York has a state tax structure that you essentially pay the higher of different calculations and this particular item we anticipate will continue into the future, so I think that's probably a fair ongoing representation.

So that will be permanently now allocated to the Network segment basically from Corporate?

Yes, yes.

All right.

And my second question I wanted to understand a little better what you're doing with AMIs here.

So you said you're going to reengage with the commission in Q4, and then a part of it is rolled into the resiliency plan.

So what -- can you maybe clarify the strategy here about that outcome?

Sure.

So we've been engaged for almost 18 months now, I think 2 years approaching on approval for this.

And of late, quite frankly, there's been minimal activity as we approach the elections.

Once we get past that, we anticipate to reengage.

Our full focus is on getting this approved ASAP, both of these, AMI and EAM.

We, quite frankly, don't want to wait for the rate case.

But realizing we're going to be filing in less than a year, if it's not done by then, obviously, it becomes a part of it.

But we think it's really important from a resiliency standpoint and meeting the expectation of our customers in New York that we get this technology in.

I mean, I think, right now, the numbers I saw is probably close -- approaching 70% of consumers across the U.S. now have smart meters.

And many in New York State have them.

So it's important we do this.

It helps in restoration.

It provides visibility, as you know, to consumers and the company.

And as I mentioned, we've gotten very supportive comments from local communities that have been some of the communities most affected this year by these numerous storms in terms of their willingness to support us in Albany with regards to this petition on AMI.

Our next question comes from Praful Mehta with Citigroup.

So great progress on your last projects.

Great to hear that, but wanted to just dig a little bit more into the quarter and the $0.10 reduction on the Networks side.

So what was the development between Q2 and Q3 that kind of pushed this down?

Or was this all kind of within the first 2 quarters with the storm impacts and EAM not coming through which, I guess, was known by the end of Q2?

So just what I'm trying to understand is what kind of drove that incremental $0.10 reduction between Q2 and Q3?

It was a combination of all those things with -- and then when we saw that our ability to capitalize labor really was one of the driving factors, we still had some storms in the third quarter, and it got to the point where we weren't able to recover any of the capitalized labor, we weren't getting in the first half in the third quarter.

And we're still seeing a, as I said, we were behind on capitalization.

Capital spending by something above $150 million at this point, so we'll recover some of that.

A lot of it is material in the supply.

It's not labor so much.

So that's kind of got us to the point of saying, "Okay, with the minor storms, with that capitalized labor, capitalized interest we weren't getting, and AFUDC." You add all those things up and being behind on our capital spending, it said we weren't going to recover this, and so we were better served by really taking an objective look at where we thought we'd come out on the Networks business, and we felt we just need to move it down a little bit.

That was really it.

It was all these onetime things that just kept building up over the first 9 months.

And whether it's large storms, minor storms, our folks have worked a tremendous amount of overtime this year and because they're working on storms and cleanups post storms, as Jim said, they've not been able to work on capital work.

So when you're behind on your capital program, you're going to be behind on the amount of labor you can capitalize.

So -- and then it impacts how much AFUDC and the like.

So it's been a very frustrating year, a very difficult year for us, but one that's certainly, I think, again, we need to focus on, okay, how do we minimize these impacts going forward because I can't say that the weather is going to materially change to the better.

And so we need to focus on the resiliency of the system and to the extent necessary adjusting the way our rate plans work to recover these costs.

That's really helpful color and put some context to the story, so that's great.

Now on the Maine side, with the new rate case, I know Jim that you mentioned, you're actually earning less than what you first you said you were overearning, but then when you looked at it in 2018, you are not.

Can you just provide some context to that?

And like how do you -- how are you positioned going into this negotiation on this rate case from an ROE perspective?

Yes, so this is Bob.

And I mentioned, we haven't increased rates at CMP distribution since the 1-year agreement we reached back in 2014, summer of 2014.

And as we've been moving through the last few years I think we've done a really good job there from an efficiency standpoint in the organization.

We also had the benefit of a -- I won't get into the details, but essentially, a tax credit we're able to generate on certain investments that we can make, and that credit peaked in 2017.

So by the time you look at where we are now for 2018, that credit's smaller.

We've increased rate base.

We have certain costs that have gone up.

We want to insert resiliency.

So the fact that the commission looked at this and said, "Well, it looks like you overearned in '17." My response will be, "First of all, there were some calculations within there as we wouldn't agree with, but we didn't get into that because we were ordered to file and that was fine", because the reality is we felt like there were certain costs and certain programs we wanted to get introduced.

So when you look at ultimately what we file for as was mentioned is the $24 million otherwise would be an increase, but we're offsetting it with tax credits associated with tax reform.

So it demonstrates the need that's there for the distribution business having not been in for what will be 5 years since by the time we get our next presumably rate increase in July of next year.

Got you.

Again, useful context there too.

And then finally, in terms of the lower ROE, you said that the rates will go up, but you will not have a final impact on customer bill in Maine, correct?

That's what I understood from your comments.

Exactly.

So what we proposed, we've only proposed a 1-year file, okay?

And it's for $24 million increase to be fully offset by tax credits by basically regulatory liabilities associated with tax reform, okay?

So customers will not see a bill increase, but it will feel to the company as if we're getting a $24 million increase.

Yes, got you.

Fair enough.

And then just one thing I wanted to clarify, the discussion early on Corporate segment and the tax and an effective tax rate.

I guess, as you are increasing your renewables, and you will get more wind assets in PTCs, shouldn't that flow through the lower effective tax rate going forward as well?

I'm sure the interest expense is going up, but shouldn't your Corporate tax rate and the effective tax rate come down too with the benefit of PTCs flowing through from the tax line?

Yes, what Doug was talking about was the management reporting, which moves PTCs up into revenue.

And so yes, you're right.

When you get the PTCs, the really effective tax rate is going to be lower.

So this is something we try to do to be comparable, but it's not -- it just gets confusing for everybody, I don't know Doug, you want to...

Yes, just to add that as you mentioned Praful, the addition of new wind farms will be directionally positive from a PTC and effective tax rate standpoint.

Just recall, those 2 that we have expiring PPAs and expiring PTCs.

And so with the expiration of those PTCs after 10 years, that has an opposite effect, so it's really the balance of the 2 that's going to drive that effective tax rate outcome.

Got you.

And have you provided effective tax rate guidance going forward or not yet?

No, just statutory.

I do have though to an earlier question that came up last year's comparison for the 9 months ended, that effective tax rate in management format was 30.5%.

So that's the comparison against for the 9 months ended this year the 27.7% in management format.

That's all the time we have for questions.

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

Well, I want to thank you all for participating.

We -- as I said, we had a good quarter and things are looking positive for the future for us.

So with that, we'll see you all at the EEI conference, I assume in a few weeks.

So thank you, all.

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

This concludes today's program.

You may all disconnect.

Everyone, have a great day.