Avangrid Inc (AGR) 2018 Q4 法說會逐字稿

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

(Operator Instructions)

It is now my pleasure to turn the call over to Patricia Cosgel, Vice President, Investor Relations.

Please go ahead.

Thank you, Andrew, and good morning to everyone.

Thank you for joining us to discuss AVANGRID's fourth 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 and 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 measures.

I will now turn the call over to Jim Torgerson.

Thanks, Patricia, and welcome, everybody.

2018 was actually a very good year for us in terms of executing on our strategic plan.

Earnings proved to be challenging as some uncontrollable weather events impacted both Renewables and Networks.

But let me start with the executing on our strategic plan.

We invested $1.7 billion in capital during the year 2018.

We had 594 megawatts of solar and onshore wind long-term contracts that were executed in 2018.

We had just under a gigawatt, 989 megawatts of onshore wind under construction for our commercial operation in 2019, and we have another 263 megawatts of contracts for our 2020 COD.

Also looking -- continuing to optimize our pipeline, we did that with the sale of 80% of the Coyote Ridge 97-megawatt wind project, and we will continue to optimize our pipeline, which now is at 13.8 gigawatts.

We'll continue to do that through the future.

We had new rate plans for both Connecticut Natural Gas and Berkshire Gas, which went into effect in 2019, and we filed a rate case for CMP and expect to file rate cases for both NYSEG and RG&E by the second quarter of 2019.

We won 2 RFPs in Massachusetts for, first, the 1,200-megawatt New England Clean Energy Connect project, and then also the 800-megawatt Vineyard Wind partnership with CIP, both of those are on track with our projections to be fully developed and operational, and we'll talk about that shortly.

And we also completed the sale of the Gas Storage noncore business in 2018.

Now the results for the fourth quarter showed $0.38 a share, and then these are on GAAP basis, and net income was $1.92 a share.

Adjusted net income for the quarter was $0.56 a share, and adjusted net income for the year was $2.21 a share.

The quarter was impacted by both weather at Renewables where we had the recent -- wind resources were down and also the continuation of minor storms.

For the year, the impact on Renewables was about $0.10 a share and for the Networks business, counting all the cost to implement -- to take care of these major -- minor storms, we had major storms as well, but the minor storms, and these are costs that are significantly above the amounts allowed in rates, along with some ancillary costs and that total is about $0.14 a share.

So those 2 items cost us about $0.24 a share for the year.

Now what we're doing about it, we looked at the wind forecasting methodology, and we moved to a life-to-date average wind resource for each wind farm.

Now that is reducing the amount of earnings by about $0.08 a share in our projections for this year.

And we all saw the impact of a number of unprecedented minor storms, we're addressing that already in the CMP rate case, and we will in New York, mainly through our resiliency plan, but also by actually trying to recover those costs of having people stand by and get in line early, so that we can address these storms when they come and we can then deal with them.

As you know, we're a public service company, and we have an obligation to serve, so we have to make sure we're taking care of our customers and getting people back online as quickly as possible.

And so we have to incur those costs.

We're also very aggressively pursuing best practices in efficiencies.

We've implemented our forward 2020 plus plan, now with a third-party consultant is helping us look at how to get more efficiencies out of the business.

We actually did reduce O&M by about $10 million to help mitigate some of the negative impacts we saw in 2018.

And the board did declare a quarterly dividend of $0.44 a share at its last board meeting, payable on April 1.

Now turning to Page 6. You can see the quarter was $0.38 a share on a GAAP basis and on adjusted earnings were $0.56 a share.

Some of the key drivers and first I want to differentiate between the quarter-over-quarter results and the results versus our expectations.

The quarter-over-quarter results were impacted by network rate plans positively, and we had increases in New York and Connecticut from the multiyear plans, but they were more than offset by impacts with the cost related to minor storms.

We had new megawatts in production, we had the sale of development projects, but we also had below-normal wind resources and then some discrete tax items.

Now versus our expectations, there's really 2 events in the quarter: one was the impact of cost related to the minor storms and this also included an adjustment for CAIDI where we have the -- we absorbed a penalty and then the cost.

Where in Maine, we exceeded the Tier 2 limitation of $10 million for minor storms that we had to incur that cost.

So those -- all those items totaled about $0.05 a share.

And the below-normal wind resource was also about $0.05 a share and the other items, you can see, offset.

We didn't get the Earnings Adjustment Mechanism in place in 2018.

That -- we'll now address that in our rate cases in New York, but we had in our plans to earn about $0.03 a share after that.

Turning now to Page 7 for the year results.

You can see, on a GAAP basis, we earned a $1.92 a share; and on adjusted basis, $2.21.

Again, the key drivers for the year-over-year results were the network rate plans, again the impact of minor storms, the production and some sales of development projects.

Versus our expectation, the negative impacts on weather for Renewables were partially offset by some O&M savings and some of the development project sales.

But the impacts overall, as I said, were $0.14 a share for the Networks business and $0.10 a share for below normal wind resources and Renewables, so that $0.10 and $0.14 or $0.24.

The other items, you can see on the page, one of the things, we had some tax and audit expenses that we incurred to help to mitigate the material weakness we had.

We'll find out if that's been done.

We are fairly confident it will be by the next week or 2 when we file our 10-K.

And then we did have some O&M efficiencies that totaled about $0.02 a share.

Turning to the next page and looking at capital spending in 2018.

Capital spending was $1.7 billion.

Renewables capital spending declined compared to 2017 and that was anticipated because of the -- we only had one small project of 10 megawatts, a solar project that was COD in 2018 versus the 590 megawatts that were being developed in 2017.

Network capital spending increased compared to '17, but was slightly lower than expected due to storm-related delays.

We did pick up quite a bit in the fourth quarter.

We were down about $200 million from our anticipated, and we ended up being down about $100 million.

So we picked up an extra $100 million in the quarter, but you can see the result was of $1.7 billion.

Now turning to the next page.

You can see our execution of strategy for Networks.

Now the NECEC project is moving forward as planned.

We did file the rate case for CMP in the fourth quarter, and we'll go through some details of that in a minute.

The final rate case decisions for our Connecticut Natural Gas was received in the fourth quarter and Berkshire Gas in the first quarter.

The New York companies, the 3-year rate period ends this April, and we expect to file rate cases by the second quarter that should be effective in May of 2020.

We have new rate years in 2019 for United Illuminating and Southern Connecticut Gas.

And we did successfully respond to the unprecedented storms in New York and Maine, getting our customers back and restore it as quickly as we possibly could.

The new projects in service, we spent $51 million on the Coopers Mills STATCOM and $85 million on the Lewiston Loop transmission, those were completed in 2018, along with the $39 million LNG modernization in Connecticut.

We completed the investments in the Smart Community in Ithaca, New York, and the battery storage and electric vehicle pilots in New York.

Now we'll be observing the results of those investments to make decisions on how we move forward with these type of activities.

The New York ISO also concluded the New York Transco AC project was the most efficient cost-effective solution for New York.

The final determination and that will be in March of this year, and we're looking at about $110 million investment as our part of it.

We also announced that $2.5 billion resiliency plan over 10 years seeking to approval in Maine, and we will seek approval for that in New York with the rate case.

Our $950 million NECEC project is on track.

The Maine Certificate of Public Convenience and Necessity that's in process and the settlement discussions are ongoing and should be successful.

We expect a decision from the Maine Department of Public Service in March and expect the receipt of all project approvals by the end of the year.

And on the next slide, you can see the schedule we have for the project itself.

NECEC, which is the piece for Central Maine Power that we have in the U.S., we're expecting the state and federal approvals by the end of 2019.

Engineering has started.

We'll make an investment in the HVDC converter.

What we'll be doing is contracting for the energy -- the engineering to begin and then once we receive all the approvals, then we'll go ahead with getting the parts, starting the construction.

Now the good thing is we can lock in the price now for that and that's one of the biggest expense items in this project.

And then the construction will commence in beginning of 2020.

In Québec, you can see the time lines there with the provincial and federal approvals, engineering, and again, there are HVDC converter contracts and their construction time frame.

Moving to the next page, you can see the Maine -- Central Maine Power rate case, it was filed October 15.

We expect the final decision in the fourth quarter of 2019.

The 1-year revenue increase will be $24 million with no net increase in rates due to some offsets by the tax reform liabilities.

The requests in Maine was a 10% ROE, 55% equity with continued decoupling.

The initial $16 million capital spending and $5 million for vegetation management are part of our resiliency plan and those are put in that 1 rate year.

The storm costs, we proposed to lower the normal storm threshold from the $3.5 million to $1.5 million per event.

And this is triggering the charging against the large storm reserve.

So that will give us a little more flexibility.

And we also included all of the 2017 Tax Act considerations.

During the year, with the Maine Public Utilities Commission order found that CMP did act reasonably in its preparation for and response to the major wind and rain storm in October of 2017.

That had been an investigation that had been ongoing for quite a while.

And then there was an independent audit of CMP's new SmartCare customer information, metering and billing system, that was done by Liberty Consulting Group at the direction of the PUC.

And they did find that the system and meters were measuring customer usage accurately and appropriate and that all components were collecting and transmitting data accurately.

Now the PUC did open a docket to review the audit findings, so they're technically really doing an audit of that audit.

And they did raise some customer communications and service questions by the audit and those will be addressed through the rate case.

Now turning to the other jurisdictions, the recent rate cases were settled in Connecticut and, as I said, we'll file in New York.

We expect to file rate cases for NYSEG and RG&E for electricity and gas in the second quarter '19.

The filing will include the companies' requests for resiliency, advanced metering infrastructure, the Earnings Adjustment Mechanism and the resiliency plan for the -- and the enhanced cost recovery for storms, including staging costs, which we're seeing an increase in that and requirements, the stage crews in advance of whether it's a major or minor storm or no storm exists at all, but where it comes through.

We're having to stage crews and incur those costs.

And those also affect what we're thinking about for the guidance for this year.

In Connecticut, the CNG rate case final decision, we had just about $20 million over the 2019 to 2021 time frame, 9.3% ROE and then the equity goes up 0.5% a year starting at 54% going up to 55% over the 3-year period.

And we continued decoupling in the trackers for system expansion and the Distribution Integrity Management Program.

Berkshire got a rate case final decision, and again Berkshire's small utility about a $2.3 million increase in our rate freeze in '20 and '21, 9.7% ROE and 55% equity and again, decoupling and pension tracker, Gas System Enhancement Program.

The Tax Act impacts, we're getting the benefits of the lower tax rates.

They've been determined in all the regulatory jurisdictions now.

And the process for addressing excess deferred tax liabilities has been determined in Connecticut and Massachusetts, and the timing and amounts are going to be determined in the upcoming rate cases in Maine and New York.

Turning now to Renewables.

We're executing our strategy and addressing the wind performance expectations at the same time.

And this really does position us to move forward successfully with our strategic plan.

We have 989 megawatts onshore wind under construction with commercial operations in 2018 -- or 2019, an additional 263 megawatts in 2020.

We added a gigawatt of long-term contracts in '18, including the 400-megawatt offshore wind.

We're optimizing the renewable pipeline with the sale of 80% of the Coyote Ridge, 97-megawatt wind project.

And all of the tax benefits went to the WEC Energy Group, who is now our partner.

We've adjusted the wind forecast methodology and also added wind boost software for 1.7 gigawatts in the fourth quarter.

And this is to address the recent years of wind performance below expectations.

The life-to-date impact is about $0.08 a share, so we've actually reduced our expectations by $0.08 a share because of our taking another look at the wind performance and going to a life-to-date, rather than the time period we had been utilizing.

So that life-to-date impact, again, is about $0.08 a share.

We're also continuing with the software implementation through additional turbines for this boost software.

We're awarded REC contracts in 2019 with NYSERDA for wind at 78 megawatts, which will be commercially operated in -- starting in 2020 and then solar in '21 for 91 megawatts.

The Vineyard Wind partnership with CIP, that's our offshore wind project, for 800 megawatts is on track.

The vendor selection, we've selected Vestas 9.5-megawatt turbines.

There'll be 84 turbines in the site.

And we have a preferred supplier agreement and -- where we've selected the offshore substation supplier.

And I also want to add that all packages for all suppliers are now in an advanced stage of work.

BOEM issued a notice of availability for draft environmental impact statement on December 3 and public meetings were held in February.

And the final environmental impact report was approved by the Massachusetts Energy Policy Act Office and allows the project to proceed with state, regional and local permitting now.

And we expect receipt of all required project approvals in 2019.

Vineyard Wind also was awarded the second Massachusetts offshore lease, which is about 14 miles south of Martha's Vineyard, 132,000 acres in the auction in December.

And you can see our project schedule for Vineyard Wind.

We expect the state and federal approvals by the end of 2019, the financing in place in the same time frame, engineering will be done in '19 and we're going to award the long-lead items this year as well.

And then the construction will commence beginning of 2020.

The first 400 megawatts are expected to be operational by the end of '21 and the next one by 2022.

We're also looking to see if we can accelerate that to get everything in '21, but that's still a work in progress.

We also, on the next page, show the New York offshore wind RFP.

The bids in New York really demonstrate our commitment and the opportunities we see in the emerging and now growing U.S. offshore wind industry.

Vineyard Wind submitted a bid in New York's first offshore wind RFP, and this is our Liberty Wind project.

That's the most recent lease we just acquired in December.

So we bid 400, 800 and 1,200 megawatts of the proposal.

The 1,200-megawatt proposal would be the most cost-effective for New York ratepayers and be one of the largest offshore wind projects in the world, if it's selected.

And the bids include substantial economic development and job creation benefits in New York, and we actually have the foundation components fabricated at a port facility in the Albany area along the river.

Liberty Wind's turbines will be in the offshore, as I said, recently acquired lease, and the transmission will tie to existing substation on Long Island, delivered by a submarine cable, and we're partnering with Anbaric to -- who is a transmission developer, who'll finance and own the transmission, and we expect the winning bidder to be decided in April of this year.

Now turning to the Page 16, our outlook.

We have GAAP earnings per share guidance would be $2.18 to $2.33 and adjusted earnings per share of $2.25 to $2.40.

As I said, we specifically looked at our guidance relative to the revised wind resource forecast and that brought it down about $0.08 a share.

We've also factored in the weather impacts and Renewables for this year, already.

We're currently down about 12% in January from weather impacts.

And this is not just wind, but it's also access to the site, ice on the blades because of the ice storms, ice we've had in the Midwest and the Northeast.

And then they can't operate when it's below the operating range when the temperature just drops too low.

So we had to shut down some of our wind turbines as well.

So that's been factored in, along with some of the things in Networks.

The requirement now that we lean in and start staging costs for major and minor storms earlier will impact us.

Now we will be addressing that as a cost recovery mechanism in our rate requests.

We already have done that in Maine, we will be doing that in New York, and we've already implemented some operating improvements, such as having crews there available 365, 24 hours a day, 7 days a week.

So that we can respond more effectively.

We're also looking at the FERC ROE decision that will have an impact on the timing of capital investments.

The PG&E bankruptcy, so far, there has been no motion to reject our contracts and our contracts, you can see in the appendix, are actually pretty much in line with market, and one of them actually expired in January.

The merchant pricing and RECs will, obviously, have an impact.

And then continuing to look at the potential sale and partnership of our development projects and Renewables.

Since we have about a 14-gigawatt pipeline, we have the opportunity to optimize that pipeline by bringing in partners, our selling projects that we may not develop in the near term.

We're also, as I said, going to be advancing our Forward 2020 Plus plan with the objective to achieve best-in-class status.

And we've brought in a third-party to work with us and accelerating that process.

So with that, I'm going to turn it over to Doug, who is going to talk about the financial results.

Thank you, Jim.

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

I'm now on Slide 18.

On this slide, we roll forward earnings per share from the fourth quarter and full year 2017 to the same period in 2018 on a GAAP basis.

As you can see, the GAAP EPS amount shows a significant impact resulting from the sale of the Gas Storage and Trading businesses and the impact of tax reform.

In the Renewables segment, we see period-over-period declines of $0.68 per share in the fourth quarter and $0.60 per share for the full year, with these movements largely reflecting the 2017 impact of tax reform on remeasurement of Renewables deferred tax balances.

The Gas segment is showing a $1.53 per share improvement for the fourth quarter roll forward and $1.58 per share for the annual roll forward.

That impact is driven mainly by a 2017 loss from remeasurement of these assets when we designate them as held-for-sale in 2017.

We completed the sale of the Gas Storage and Trading businesses in the second quarter of 2018.

I'm now on Slide 19.

We show our adjusted earnings roll forwards for the fourth quarter and full year, which excludes the Gas Storage and Trading businesses that we exited in 2018, impacts of the 2017 Tax Act, Renewables mark-to-market, restructuring charges and other items.

Moving to the charts on the slide.

You can see that adjusted EPS declined from $0.61 to $0.56 per share when comparing the fourth quarter results, while the full year results were relatively flat with 2018 earnings per share at $2.21 and 2017 at $2.20 per share.

Both roll forward comparisons are largely affected by the same earnings drivers.

As Jim noted, during the fourth quarter, we continue to have challenging conditions with ongoing storm-related costs in Networks and lower-than-normal wind resource offsetting the period-over-period increases that we experienced from rate plans at United Illuminating, Southern Connecticut Gas, Connecticut Natural Gas in our New York companies as well as the positive impact from new capacity that we added in Renewables in late 2017 and 2018.

Lower Corporate earnings in the quarter-over-quarter and year-over-year periods primarily related to tax impacts, new debt issued at AVANGRID in November of 2017 and the absence of intercompany interest income from the gas businesses in 2018 from their sale earlier that year.

Now on the next several slides, I'll provide more detail on the business segment impact.

Starting on Slide 20, this summarizes the results and business drivers for Networks.

For the fourth quarter, you can see the results were down quarter-over-quarter by $0.07 to $0.35 per share and down year-over-year by $0.07 to $1.57 per share.

We experienced the $0.06 quarter-over-quarter and $0.21 year-over-year benefit due to rate increases in our New York utilities, which were in the third rate year that began on May 1, 2018; in UI, which was in its second rate year; and in SCG, which is in its first rate year.

For the year-over-year comparison, Networks also experienced the benefit of $0.03 due to over earnings in 2017 that did not recur in 2018.

These positive impacts were reduced by nondeferrable minor storms and related costs, which continued through the fourth quarter.

Networks experienced $0.06 loss related to the nondeferrable minor storms and related costs quarter-over-quarter offsetting the quarterly rate benefits and a $0.15 loss for the year-over-year comparison.

The storm impacts include the direct costs of the minor storms as well as lower capital spending from these events, which translate into lower capitalized labor and AFUDC.

In the fourth quarter of 2018, these related costs also included a CAIDI penalty in New York and the exceedings of a minor storm threshold in Maine, which together was a $0.02 negative impact.

Going back now to other drivers within Networks, the remaining impact that reduced the benefit of higher rates included higher depreciation due to new investments and a shift from Corporate to Networks of a New York capital base tax charge.

At the consolidated AVANGRID level, this New York capital base tax charge is a $0.01 negative impact to both 2018 and 2017 earnings.

However, the movements between Corporate and Networks in 2018 for this item are causing a $0.03 negative impact to Networks and a positive $0.03 to Corporate for the quarter, along with a $0.04 shift for the full year-over-year comparison.

In addition, there were energy efficiency performance incentives earned in 2017 that expired and those were not replaced with an Earnings Adjustment Mechanism in 2018, which resulted in a decline for the quarter-over-quarter and year-over-year comparisons of $0.03.

Now turning to Slide 21.

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

Performance for the fourth quarter was a positive $0.10 per share year-over-year improvement with earnings from our new wind capacity added in 2017 and 2018 contributing $0.03.

Earnings from our existing resources were up $0.01 per share, driven largely by sale of our second smaller claims from the FirstEnergy Solutions bankruptcy, net of the impact of selling power from these wind farms at the lower merchant prices.

Wind production quarter-over-quarter was lower for existing assets of approximately 9% and that was primarily in the mid-Continent.

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

In the third quarter, we sold a transmission queue position that added approximately $4 million after tax or $0.01 per share.

And in the fourth quarter, as Jim mentioned, we earned $0.02 from the sale of 80% of our Coyote Ridge wind project to WEC Group.

Other minor impacts related to PTCs, RECs and earnings in our Thermal and Trading business, which includes our Klamath Cogeneration and Peaking Plants.

Our 2018 year-over-year performance was positive $0.21 per share and that largely reflects similar impacts for the quarter.

New capacity contributed $0.06 per share year-over-year.

Wind performance at our existing facilities was relatively flat compared to last year, although it was lower than our expectations for normal wind by approximately $0.10 on the year.

In addition, our results for new wind and solar included negative $0.05 per share impact from the transmission issues that we had with our El Cabo and Tule wind farms in the second quarter.

The full year-over-year impacts of existing wind also include positive FirstEnergy Solutions bankruptcy impacts of $0.04 and that consists of $0.06 from the sale of 2 claims and receipt of collateral plus $0.02 and lower gross margins from selling this output into the merchant market.

Now turning to Slide 22, we take a look at the Corporate segment.

This is largely driven by financing costs and taxes.

At the Corporate segment, adjusted earnings per share was lower at $0.07 for the fourth quarter of 2018 versus 2017 and lower at $0.13 for the full year 2018 versus 2017.

These declines are largely driven by large positive state tax adjustments that we incurred in the fourth quarter of 2017 and this was not as large in 2018.

In addition, the Corporate segment reflects higher financing costs from the issuance of our green bond in November of 2017 and also the absence of intercompany interest income from the gas businesses that we exited earlier this year.

The overall AVANGRID consolidated effective tax rate for 2018 before discrete items was approximately 17.1% on both a GAAP and an adjusted basis.

And then after discrete items, the consolidated effective tax rate was 22.2% on a GAAP basis and 13.8% on an adjusted basis.

Moving to Slide 23, we show our cash flows for 2018 with cash from operations, which covered our investment needs by $227 million.

We paid $537 million in external dividends, and then we raised debt approximately $307 million and other financing to cover the net need.

Now moving to Slide 24, this shows our strong financial position, which gives us the flexibility to fund our growth, including the New England Clean Energy projects that Jim mentioned.

Those are the New England Clean Energy Connect transmission project and the Vineyard Wind partnership for offshore wind as well as ongoing safety, reliability and resiliency investment opportunities.

Our debt level, net of cash, at the end of 2018 was $6.4 billion, and our credit metrics remained very strong.

We're at 3.2x net debt to adjusted EBITDA, 29% leverage and 22% cash from operations before working capital as a percentage of debt.

Our credit metrics are certainly very important to us, and we've maintained our stable BBB+ and Baa1 ratings with the rating agencies.

On Slide 25, we highlight our dividend and dividend policy.

In the third quarter of 2018, we increased the quarterly dividend from $0.432 per share to $0.44 per share.

We also retained our target payout ratio of 65% to 75%, and we expect future increases of that to be in line with our EPS growth, subject to this target payout range.

Finally, on Slide 26, as Jim mentioned earlier, we're setting our consolidated earnings outlook for 2019 to $2.25 to $2.40 per share on an adjusted basis.

When we set this guidance, we considered the effects of the recent years of wind performance as well as the 2018 storm impacts that Jim covered earlier.

In our Networks business, we'll benefit from higher rates through our rate plans, but we've also conservatively assumed higher level of minor storms at about half the level that we experienced in 2018.

We're taking steps, as Jim mentioned, to address the impacts of storms on our Networks business, including requesting in rate cases to raise the allowance for minor storms, lowering the threshold for recoverable storms, increasing recovery for staging costs and implementing our transforming energy resiliency program with vegetation management and resiliency capital spending.

However, those impacts won't be in effect until 2020, and that's the need for building more conservatism into our 2019 guidance.

We're also assuming in Networks a positive FERC ROE decision in 2019 that's in line with the most recent order.

In Renewables, Jim mentioned, we've revised our methodology for forecasting normal wind to reflect life-to-date performance.

This impacts by approximately $0.08 per share negatively our view now on normal wind.

The 2019 guidance also reflects estimates of roughly $0.05 to $0.10 per share for strategies that optimize our Renewables pipeline through potential asset sales and partnerships.

And then, also, as Jim mentioned earlier, in 2019, we're having a challenging start with our wind resource and weather in Renewables with production down approximately 12% below our expectations due to wind resource and weather.

I'd estimate that's roughly a $0.02 to $0.03 per share impact to the quarter.

However, we do expect to overcome that for the full year through the efficiencies from our Forward 2020 Plus plan and the efforts in that area.

We do assume in our guidance the consolidated AVANGRID effective tax rate before discrete items of approximately 20%.

Now moving to Slide 27, we conclude with some highlights for our company.

We highlight our attractive wind -- excuse me, attractive investment opportunities in our Networks business, in our Renewables business.

Winning key awards in 2 major RFPs and moving forward on track with these New England Clean Energy projects.

With our access to 3 leases now, we're a leader in the U.S. offshore wind business.

And we also want to emphasize our leading role in the U.S. as a sustainable energy company, having the first carbon neutral energy target, which we're committed to achieve by 2035.

We have a distinctively strong balance sheet and solid investment grade credit ratings, and we're committed to increasing our dividend in line with our 65% to 75% target payout ratio.

With that, we look forward to seeing everyone at our Investor Day on February 26 at the New York Stock Exchange.

And I'll now hand the call back to Andrew for questions.

(Operator Instructions) And our first question comes from the line of Praful Mehta with Citigroup.

Our next question comes from the line of Julien Dumoulin-Smith with Bank of America.

Can you hear me now?

Yes, we can hear you, Julien.

Excellent.

Perhaps just wanted to start off here on the '19 guidance.

Can you walk through a little bit on what your earned ROE expectations are and baked into that a little bit by segment?

Obviously, you've got a number of different moving pieces, rate cases on the come this year.

And how are you thinking about CMP specifically given the dynamics there, if we can start there?

CMP, we're probably not going to have an order till the fourth quarter of 2019.

So we have very little guidance for that, and we'll be earning basically on the rates we have in place today.

For the other one, I don't know, Bob, do you want to address where you think?

Yes, sure, Julien.

For New York, it's, obviously, going to be a very important case that we file for a host of reasons.

First of all, we have the resiliency plan, we have AMI, a number of different investment initiatives that we need to get approval for.

But importantly, and Jim and Doug both spoke to this, I think what we have experienced over the past year in calendar year '18 was truly atrocity in terms of the frequency of the storms.

In addition, I think, given the frequency, we're seeing a heightened sense of -- or, I should say, a heightened expectation on the part of our customers, regulators, local community leaders with regards to the speed at which we restore power.

And as Jim touched, this -- these required us to use a lot more in terms of, what we call, staging costs, moving folks around, getting our contractors prepared should a storm occur, and as a result, we had a significant impact of that in '18, and we would expect until we get that -- those types of costs reflected in our next case, the risk would continue in '19 and the early part of '20 in that regard.

Now I don't anticipate -- well, it's not impossible or I don't anticipate the level of storms we saw in '18 and '19, but there will be a continuing lag associated with that.

So that would be the main piece that, I would say, would potentially create a drag on our results in New York for calendar year '19.

I think in the -- Julien, the other areas, we're targeting right now, New York aside, to be looking at earning the allowed returns in our different areas.

And we've been doing that.

And historically, we've done it quite frankly, in Maine, in New York as well, but given some of the headwinds we've seen, '18 proved to be extremely challenging until we get the rate structures aligned to reflect kind of the new reality on storms and the cost associated with that.

It will be difficult to achieve our past performance during '19.

Got it.

Excellent.

And can I come back to a little bit of the commentary you provided in the prepared remarks on Maine, specifically?

You said on the CPCN, on NECEC that it's in process and settlement discussions are ongoing.

Can you perhaps elaborate on the process there specifically and the time line here?

Do you think about the Maine Department Public Service in March?

And how the timing might align against -- well -- I'll let you elaborate?

Yes, yes.

Sure.

So we -- I mean, we've been having discussions for some time now with many of the parties that are a part of the CPCN proceeding.

And I think we've made good progress in terms of looking at getting broad support for the project.

We're obviously not there yet.

We do think that this -- we'll continue to be on track for getting our final approval for the CPCN by the end of March.

Obviously, there have been some rumors floating about as to where we are in discussions.

We can't speak to that.

Those are confidential discussions.

But if and when something is reached, it will be made public at that time.

But we -- as Jim said in his remarks, we feel good that we're on track in getting that CPCN by the end of the first quarter of this year.

But sorry to just clarify this.

I mean, we're a month out.

Just in terms of process for a vote out needing to get commentary back on any settlement.

I just want to understand just even the time line and process for that to happen by end of 1Q?

Yes, so we recognized that even while we've had settlement discussions, the litigated time line has continued.

So whether we reach a settlement or not, the time line is such that it's planned for commission deliberations at the end of March.

So in one instance, if we're able to reach a settlement, that would get introduced into proceeding and there is sufficient time for that to get introduced and decided on.

And if not, then the normal litigated track would apply.

But again, both of those time lines would result in a decision by the commission by the end of March.

Got it.

Excellent.

And then just going back sticking with Maine here, I mean, how are you thinking about opportunities outside sort of inorganic opportunities at the utilities, again, relative to what seems like -- and I'd like some clarity with respect to some of these upgrades that may or may not be fully included in the outlook as it stands today just to clarify that piece, too?

Maybe you can just clarify what beyond NECEC is an inorganic?

What are you focusing...

Specifically, utility acquisitions.

Any latest thoughts on that?

Obviously, there's a lot of different developments in the sector.

Would be curious on what you always saying today on that front?

And then separately curious on -- you obviously have a lot of different projects moving here.

It seems like some of those projects you discussed in your prepared remarks are not included in your formal rate-based guidance at least from last year's outlook?

Yes, as far as M&A, we don't comment on that, Julien.

I mean, I know you know that, so we can't comment anything there.

I mean, our focus, Julien, in Maine is strictly on a couple of things right now.

So one, obviously, is serving the company, meeting the customers rather than meeting their expectations.

It's on getting the approvals for NECEC, and it's on getting through the rate case and the outstanding review of the billing system and getting customers some assurance that they are effective and accurate in terms of the bills that are being produced, which has been shown now by 2 different audits.

But to be very frank, there are still people that don't believe that, and so, as Jim said, the commission is going to investigate it further and do an audit of the audit, if you would, to just make completely sure that the system is operating as designed.

The other projects we mentioned a couple, the Lewiston line and the -- those are things that we've got.

Those are just ongoing typical projects that we would do in any jurisdiction to improve the transmission system and the smart grid.

So those are things that are just ongoing all the time.

Any other projects that we have that we have talked about in the past are a little further along, one of them is in process is MEPCO Rebuild.

I mean, that's continuing as we anticipated as well as Brightline Investments, that's continuing.

So nothing's really changed in that regard.

And our next question comes from the line of Praful Mehta with Citi.

Sorry about the confusion earlier.

No problem.

So wanted to just understand, on 2019 earnings, you have a good slide here on Slide 16 with key risks and opportunities and wanted to understand the $0.08 impact you've already talked about for Renewables on capacity factors.

What are the other big drivers on the network side that could push you to the upper end or lower end of the range that you provided right now?

Well, we gave the $0.08 that pushed the range down -- our guidance down, frankly, so the $2.25 to $2.40 for adjusted.

Some of the other areas that we took into consideration, one is, as Doug mentioned, just the fact that we're down 12% from weather impacts and Renewables on production already this year through January.

So that's something that we've already taken into account.

The lean in and staging costs that Bob and we talked about, those are things that we feel will impact us and we've basically taken that into consideration when we look at how we developed the guidance.

So those are things.

Now the things that could improve wind performance, let's assume it gets better.

So far we haven't seen that, but if you look at history, there are opportunities for the wind to actually pick up, and we could do better.

So that could go either way.

But to be conservative, we brought it down.

So looking at life-to-date for all of our assets.

The other areas depending on how much we can implement from our Forward 2020 plan that would allow us to get cost efficiencies this year, that would be another one that could be an upside for us.

And then the FERC ROE decision, we factored something in for that.

We don't know where that one is going to go, but if it's along the lines of what the initial decision they put out that they got -- that we then briefed then we would -- that's been factored in.

So -- I mean, Doug, any other...

No, I think those covered the key points from my point of view, Jim.

Okay, great.

That's super helpful.

And then the $0.08 impact in '19 if you had to play that forward through your forecast period, do you expect to change in long-term growth rate views as a part of that reset of capacity factors?

We think that resetting the capacity factor is going to be ongoing, that's going forward.

We'll keep looking at it every year to see if our thoughts change, but right now, I would expect that to be taken forward into our longer-range view.

Understood.

So you do expect some impact from it in the long-term view as well?

Yes, yes.

I do.

Okay, understood.

And then, finally, on Slide 39, in terms of the PPA pricing and merchant pricing, there seems to be -- kind of been a pickup in merchant pricing in '18.

Is that -- can you just touch on that, particular markets that kind of helped?

And how do you see that going forward in '19?

What's kind of built into your '19 numbers view on that merchant pricing perspective?

Well, Laura's on, maybe she wants to comment on that one.

Yes, sure.

I mean, everyone, I think, is clear that gas prices are really what's driving merchant prices for the most part and what we experienced in '18 is some shortages in key areas, which drove really, really high prices in -- both the Northwest and also in the Texas area because of some of the capacity scares with hot temperatures in the summer.

And so we've really priced in just what we expect based on the fundamentals, but I will say that gas has been pretty steady, along $2.70 per MMBtu, and we tend to see upticks when there are unexpected supply conditions.

And so to the extent that we experience additional shortages in areas this year, and we've already seen some so far early in January in the west then we could potentially see some upside in merchant prices, but we have not baked that into the earnings profile for '19 as of yet.

And our next question comes from the line of Greg Gordon with Evercore.

It's actually Phil here for Greg.

He's jumped on another call.

Just a couple of items here.

First, how realistic is it for us to assume you'll be successful getting a regulatory fix for the storm issues?

Are there any -- are peers in those states lobbying for anything similar?

Or are there other jurisdictions you could point the commissions to that have similar thresholds and the other elements you're requesting?

Any color on how receptive the commissions might be to what you request?

Yes.

This is Bob.

I think they will be.

I mean, I think there's a recognition that -- as I mentioned earlier, there is a heightened expectation around the speed of storm restoration and preparedness that is necessary for storms given the increased frequency we've seen.

So I don't, at this point, foresee any issues with regards to getting it right if you would in our next case.

The issue for us is, obviously, the next case we filed in the second quarter this year would be effective in May of 2020.

So we would continue to be at risk and focus now on New York to what we experienced in '18, which was unprecedented, but to some extent in '19, particularly around staging cost because that is just an expectation that is there.

But I do not foresee a problem getting this reflected.

We do, for example, right now, 3 years ago, when we reached the deal we have now in New York, we were allowed the deferral of some staging costs, basically 2 instances a year and at Rochester 3, at NYSEG so long as the staging costs were over $0.25 million in that -- in those instances.

But what we found is that probably was 10, 12 of those types of storms, where we staged, but nothing ever materialized or it wound up being a very minor storm and the costs weren't deferrable.

So it's more updating of assumptions around -- based upon experience of what we're going to use for the next rate file.

Got it.

Okay.

So until that point though before you get a regulatory fix, it sounds like we should think of this as impacting your ability to earn your allowed ROEs in those jurisdictions.

But the O&M efficiencies, the couple of pennies you managed in 2018 that kind of helped to mitigate those uncontrollable items.

Should we think of that as indicative of your ability going forward or do you think you could achieve more significant cost reductions prospectively to the extent you have to?

Well, I mean, we look at that year in, year out.

That's really a part of what our Forward 2020 process is.

As Jim mentioned, we're using a third-party now to help us in that regard as we look at calendar year '19 and going forward.

So from that perspective, I think you'll continue to see us do well and be as efficient as possible and run the business more efficiently, but some of these costs that we saw particularly in 2018 are at a level where you just realistically cannot find that level of efficiency in the business to offset that.

And I think the cost that we saw, the $0.02 improvement, were the things, what I'll call, around the edges where we cut certain things out.

Whereas, what we're looking now in our Forward 2020 is how do we really drive long-term efficiencies into the business in transforming some of the ways we do work.

So I would expect that we would see some improvement in that going forward.

And that's really the objective to get as efficient as we can.

We want to be the top tier in the industry on efficiency.

And we have a little ways to go to get to that point.

So that's really our goal.

And so it's -- that's what's been driving us now to get a third-party to help us with this and work through how do we look at the way we actually operate, the reports we generate, the levels of management.

All -- we're going to be looking at all kinds of things there, so that's really the objective.

Okay, and last question.

Can you just kind of talk about the growth of the renewable pipeline versus EEI?

It's just a bit hard for me to decipher the delta.

But I'm not sure I saw anything meaningful in there.

Yes.

Well, we have the 4 gigawatts of offshore wind and then 9.8 of onshore and solar.

The solar is the one that's grown the most.

And it also does not include the new lease we have for offshore wind, which would be, I guess, in our partnership about another gigawatt.

So Laura, do you -- can you give him the breakdown between what we added in solar and wind since EEI?

You're absolutely right, Jim.

The vast majority of the additions have been on the solar front.

And when you say, since EEI, are you referring to the pipeline or are you referring to the PPAs that we announced at EEI?

The pipeline.

Yes, the pipeline.

There was a slide that I don't see replicated in this one, relative to the 2.7 gigawatt target by 2022, I believe, it is and those that are...

Yes, those are PPAs, the 2.7 gigawatts of PPAs.

Right.

So how does that look today, I guess?

Yes.

And so we announced at EEI the addition of the 210 megawatts of solar.

And then in Slide 13, you'll see that we did sign 2 additional contracts with NYSERDA for an additional wind project late '20 and then a solar project, 91 megawatts, in '21.

And we are continuing down the process of PPA negotiations with counterparties.

We've got numerous projects that are shortlisted.

There have been a lot of RFPs in recent months, and I can tell you that for the most part, the dates for the final selection continue to get pushed out and so we are just awaiting the ability to be able to announce projects when -- if and when they come to fruition, but so far since EEI what we have announced is the 2 contracts with NYSERDA.

And our next question comes from the line of Insoo Kim with Goldman Sachs.

Just on the Liberty Wind proposal, I don't -- I apologize if I am late to the information, but what's the anticipated service date if that is a winning bid in New York?

I believe -- Laura, you can correct me if wrong, but I think it's like 2027.

I'm not sure if -- I think that was redacted in the bid.

But yes, I think it would be targeting 2026 time frame, likely.

Yes, it's after 2020.

Well, I know that, so it's later in the decade.

Got it.

And when you think about the bids that you put in for the 3 different capacity levels, I assume that you're still sticking with the strategy of trying to achieve around a couple hundred bps above the cost of capital?

Yes, that is our target and keep in mind that the cost of capital is reflective of the risks related to an offshore wind project, so it would be higher than that we use for onshore wind or solar.

Understood.

And then on the capacity factor front, I recognize the adjustments you've made on the methodology, in terms of the new wind capacity factors for, I guess, the newer wind facility that are coming online.

I know the previous guidance was around 40% for the capacity factor.

Is that something you're able to say whether you're confirming or should we just wait until next week?

I don't know.

Laura, do you want to...

Yes.

Most of the reductions that were required were on what we were considering our existing fleet and that was the fleet that had been added up through 2015.

The newer facilities are a higher capacity factor just simply because of the technology.

And, of course, we do have such a diverse footprint of operation.

You're going to see lower capacity factors even for new facilities in the Northwest, for instance, but you're going to see much higher capacity factors for facilities in the Midwest.

So I think the average for the new is going to be right around what we had been communicating where you're really seeing the life-to-date adjustments is on what we're considering to be existing.

So we're still looking on the new stuff mainly around 40%.

We'll give you a little bit more detail on that next week, so what we had...

And our next question comes from the line of Michael Sullivan with Wolfe Research.

So yes, I just wanted to start with -- I know you laid out kind of a lot of the drivers in '18 and then also in '19 guidance, but can you just give us a sense of what you would consider a normalized 2018 number and then how much of some of those headwinds we would expect to reverse in '19 and then in '20?

Just if we could put some numbers and cadence around that?

Yes, this is Doug.

In terms of 2018, I think, Jim called out in one of his slides the specific items versus expectations, minor storms, the lack of EAM, sale of development projects, et cetera.

I think specific to those, the normal wind resource, the minus $0.10, we certainly hope never to repeat that outcome again, but we have adjusted our guidance in 2019 to address that by $0.08 per share.

Specific to the minor storms, I mentioned earlier, that we think of that more as roughly half of what we experienced in 2018, on a recurring basis in 2019.

And as we have the ability to adjust our recovery process, we hope to see that impact diminish and eventually go away.

On the development projects, on Slide 7, we do anticipate in 2019 to be selling further development projects and that has a roughly $0.05 to $0.10 opportunity built into our guidance.

The transmission issues, obviously, that was, hopefully, onetime event, and so I don't expect further downside impacts in that category.

And then on the O&M efficiencies, we think there is good opportunity there, incremental to what we've done in 2018.

So there is some degree of improvement versus 2018 that we're assuming in our 2019 guidance.

As far as the EAM, we're not assuming anything in 2019 for that.

I think more just to be conservative and if we have success there, certainly that would be an upside, but that's not part of the base guidance.

The EAM, we won't see that until 2020.

Yes, mid-2020.

Yes, yes.

Okay.

And maybe can you just give any more color on the Forward 2020 initiative?

It sounds like what you're saying is you were able to offset the Renewables' weather impact to date of $0.02 to $0.03, but how much are you baking in for the full year?

What I think Doug was saying is, over the course of the year, we think we would offset at the $0.02 to $0.03 that we're seeing in the first month of the year for Renewables.

We haven't really given a number for the efficiencies because we just started the project with our third-party.

So I don't have a number yet that I could give you, but suffice to say, we expect to see some benefits from that project.

It will probably be more than the $0.02 we saw.

Okay.

And then last one, I know you're going to get into this probably a little more next week, but I just want to clarify when you guys reiterate your long-term growth rates which we did as of EEI.

When you're doing that, is that just kind of going back to when you first put that out there?

Or are you kind of actively refreshing and looking at the plan on sort of an ongoing basis such that as of November, you still did think those growth rates were good?

And if so, what's really changed since then outside of the Renewables' capacity factor assumptions?

When we put that out like at EEI, we take a look at it, but we don't -- that was really the number we had done as of February 20, 2018, that was a year ago.

We kind of look at it, but it's as of that date, as of February.

It wasn't that we renewed it.

We redo it once a year, the long-term look, which is what we'll be doing for next week in looking at our long-term growth prospects.

So I mean, we think about it, but I can't say that we -- at EEI, we did not actually do anything other than, say, was as of the one from the Investor Day in February of 2018.

And our next question comes from the line of Paul Patterson with Glenrock.

Just a few quick sort of quick ones.

With respect to the auction in New England and the failure to get appropriate results there for you guys.

And given sort of [Chatterjee's] previous indications about price suppression from Renewables the sense that he -- that was at least attributed to him?

What do you guys think about in terms of -- how should we think about your ability to clear the auctions for Vineyard Wind, et cetera, and the impact on the economics of the project?

I think longer-term, we will clear the auction, it's just a matter of when.

We're pursuing, what I consider, our rights under the Federal Power Act right now, and we'll be pursuing whatever we need to, to make sure we get into the auction appropriately.

So -- but I believe that we ultimately will succeed in getting the capacity.

Whether it's the first year or the second year, it will have somewhat minor impact, but long-term when we're looking at project, that's going to be there for 40 years, let's say, 20 for sure on the contract that, I think, will be successful.

Okay.

So the idea that, I guess, when you say the second year, under the current rules, et cetera, would there need to be an additional waiver or how should we think about in terms of the process for the FCA 14, I guess?

And...

We did get -- yes, go ahead.

No, please go ahead.

We got 54 megawatts, unfortunately, we bid it at 0, which is what you would expect for the replacement auction.

So that's not going to help a lot.

Going forward, we will expect to get either -- we have to get a waiver, and now we will work with ISO New England and the others to see if we can avoid that process to have to have a waiver.

And because they did approve the change in the tariff that allowed us to get into the auction.

So they were looking for us to get a waiver.

So we'll be working with them on that.

I don't know, Laura, do you want to add anything there?

Yes, I mean -- I guess, I would just reiterate that the -- it's become very clear, I think, that ratepayers are going to pay more because Vineyard Wind was not able to participate fully in the market in the capacity auction, and it was really, from our perspective, a technicality that caused that.

There was no rejection of our eligibility, and so we are going to continue to pursue that.

We think it makes sense, and we think it makes sense for ratepayers and we're exploring all avenues available to us to see if we can make that right.

No.

And I understand your guys' position and the logic of it completely.

I guess, the concern is, is that you're going to have a Republican majority.

It seems eventually -- I don't know how many months now.

And it appears that there was this impasse because it was sort of a 2-2 vote certainly in the [rereads] and sort of statements that were made.

And I guess, the idea is, is that if there is a position that there's this price suppression issue, you know what I'm talking about, whether or not these guys might try to basically change the original outcome of the ruling that they made, in other words, [the Chatterjees] then starts to actually show up is as an actual policy, if you follow what I'm saying.

Yes, I do.

I -- as I said, we will pursue our rights under the Federal Power Act, and we'll keep working on this one.

Okay.

I understand where you are coming from.

And then just with the average life-to-date -- and I'm sorry, if I missed this, this was asked just now.

When you mentioned the new capacity factor, you said that was for existing stuff and that new stuff, I think, was more around the 40% capacity factor.

Did I hear it correctly?

Could you just elaborate a little bit on that?

And how that compares with your offshore expectation?

Yes, the capacity factor for new onshore, it varies, obviously, site-by-site, but generally, it's around 40%, I think, is the way to look at it.

And the offshore is actually better than that.

I don't know, Laura -- I know you said it's around 50% is kind of the...

I think -- yes, for Vineyard, specifically, I think it's been in the range of approximately 50%.

Okay, and that hasn't changed at all since the existing -- if I understood you guys correctly, with the existing facilities that you guys have changed the average life.

Right.

Right.

Capacity factor.

Okay.

And then just in terms of -- right.

The capacity factor, I apologize.

And then in terms of the firm EPC -- potential for firm EPC on offshore wind, where do we stand with that?

Well, I think I said there is like 7 packages that we have for all the different components, whether it's the turbines, the foundations, the transition, whatever.

They are all in advanced stages of work right now, and we feel pretty good about being able to get that done in a very timely fashion and lock in the prices and all the different suppliers.

But it's not one EPC I'd characterize it, there are 7 different ones that we're working with.

Okay.

And you guys are looking to sort of firm those up to sort of for risk mitigation purposes, do I understand that correctly?

Yes, we've already have a contract for the Vestas turbines, and we have a preferred supplier for the offshore substation already.

So those 2 -- and those are 2 of the bigger components are already taken care of.

Okay.

I'm not sure if just the actual construction of the facility in terms of just getting it -- I guess, in terms of not just the components but the actual setup itself...

Well, that all goes into these 7 packages that we have.

Some of that, it's the logistics of the shipping.

It's the ships and who -- how the construction will be done and so on.

So that -- what I'm saying is, all those things are in an advanced stage, right now, of negotiations that we expect to conclude pretty soon.

And ladies and gentlemen, that does conclude our question-and-answer session for today.

So with that, I'd like to turn the call back over to CEO, Mr. James Torgerson, for closing remarks.

Well, thank you very much.

As you can see, we're actually very happy about where we are at with our strategic plan, being able to implement that and going forward, and we'll be talking to you next week at our Investor Day about what we see for the future.

So look forward to seeing you all next week, and thank you for participating today.

Thank you for participating in today's conference.

This does conclude the program, and you may all disconnect.

Everyone, have a wonderful day.