Avangrid Inc (AGR) 2019 Q2 法說會逐字稿

Hello, and welcome to the Q2 2019 AVANGRID Earnings Conference Call.

(Operator Instructions) I'd now like to introduce your host for today's call, Patricia Cosgel.

You may begin.

Thank you, Twanda, and good morning to everyone.

Thank you for joining us to discuss AVANGRID's Second Quarter 2019 Earnings Results.

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

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

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

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

Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in AVANGRID's earnings news release, in the comments made during the 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 statements.

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

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

I will now turn the call over to Jim Torgerson.

Thanks, Patricia, and good morning, everybody, and thank you for joining us today.

Here with us also we have Bob Kump who is now Deputy CEO and President for AVANGRID; Laura Beane, who is the CEO for our Renewables business; and then Tony Marone in his inaugural call as the CEO for Networks.

So I want to wish them all well today.

And Tony, you get to join in from the phone.

Let's start out.

For the second quarter of 2019, net income was $110 million or $0.36 a share.

Year-to-date net income was $327 million or $1.06 a share, which was down about 7% over the year.

Our adjusted net income in the second quarter was $101 million or $0.33 a share.

Year-to-date adjusted net income amounted to $319 million or $1.03 a share, which was down about 14% against 2018.

Now we were disappointed with the continued lack of wind resource that impacted most of our fleet.

The lower-than-expected wind and the impact of nondeferrable minor storms and staging costs caused our earnings to be below our expectations for the second quarter and year-to-date.

We are implementing various initiatives of our Forward 2020+ plan to partially mitigate the reduced revenue and cost increases, and we're confident that this initiative will enable us to achieve our strategic and financial goals in 2019 and beyond.

I also want to mention that most of the efficiencies will be recognized in the second half of 2019.

Also, we're continuing to execute on our strategic plan objectives.

Now our New England Clean Energy Connect transmission project is on track.

And recently, the Massachusetts DPU approved 20-year contracts between Hydro-Québec and the Utilities.

And those utilities are Eversource National Grid and Unitil.

In New York, NYSEG and RG&E filed their electric and gas rate cases in May for new rates effective in the second quarter of 2020.

This includes requests for recovery of resiliency investments and deferral of the staging costs that we're experiencing.

Our Patriot Wind 226-megawatt wind farm was purchased upon commercial operation in June and our 763 megawatts of renewables, those are assets under construction, and they are on track to come online by the end of this year.

For our Vineyard Wind offshore project, as you probably know, we were recently informed that the Bureau of Ocean Energy Management has delayed the final Environmental Impact statement.

However, we are confident that the pending reviews can be concluded shortly, and the final EIS released soon after.

Vineyard achieved other really relevant milestones during the second quarter, including the approval from the Massachusetts Energy Facility Siting Board, which is an independent state board responsible for the review of proposed large energy facility as well as the regional development review permits from the Cape Cod Commission and the Martha’s Vineyard Conservation Commission.

To date, we have secured about 80% of the supply chain and the remaining 20% of the contracts are in final stages of negotiations.

During the second quarter, we entered into a new PPA for 140 megawatts for the La Joya ll onshore wind farm in New Mexico.

On the financing side, we successfully issued our second green bond in May for $750 million, and the coupon was under 4%.

In addition, on July 16, the Board declared a third quarter dividend of $0.44, payable October 1.

On Slide 6. For the quarter, GAAP earnings per share was $0.36 a share, up $0.01 versus the second quarter of 2018.

The adjusted earnings per share was $0.33, which was down $0.08 or 22% versus the second quarter of '18.

For the first half, GAAP earnings per share decreased $0.07 or about 7% to $1.06 and adjusted earnings per share decreased $0.17 or 14% to $1.03.

The key drivers for the first half results by business are for Networks first, adjusted earnings per share decreased $0.04 or about 4% year-over-year to $0.86 per share.

The results reflect the impact of higher depreciation, which is about $0.06 a share, higher nondeferrable minor storms and staging costs and these negative impacts more than offset the contributions from our multi-year rate plans in New York and Connecticut.

And for Renewables, adjusted earnings per share decreased $0.15 to $0.22 per share, significantly -- were down about 6% year-over-year on wind production.

And that was primarily and probably due to significant lower wind resource and extreme weather conditions in the first quarter.

The year-over-year comparison was also affected by lower prices and expiring of PTCs.

This was partially offset by higher revenues from Klamath, which is our gas combined-cycle facility that added about $0.04 and as a result of lower renewables production and the volatility of prices in the West.

Now flipping to Slide 7. Today, we're revising our guidance and lowering by $0.05 to the high end of our consolidated 2019 GAAP earnings guidance to $2.18 to $2.28 per share compared to the previously reported guidance of $2.18 to $2.33 per share and adjusted earnings to $2.25 to $2.35 per share compared to the previously reported $2.25 to $2.40 per share for 2019.

Now this update primarily reflects in Networks the impact of staging costs, minor storms and the expected resolution of 2018 storm proceedings in New York, which are going to be partially offset by Forward 2020 efficiencies.

In Renewables, in addition to the lower-than-expected wind resource over the first half of the year, we had weather-related delays for construction projects in Texas, with Patriot purchased at COD in late June, rather than as expected in May as well as the delay for Karankawa.

This has probably cost us about $0.04 a share versus expectations for 2019.

And again, these results are going to be partially offset by the efficiencies gained from our Forward 2020+ plan.

Impacts related to minor storms and the staging costs in Networks and low wind and extreme weather renewables, we're approximately negative about $0.15 for the first 6 months versus our expectations.

Now the number of minor storms increased by approximately 40% in the first 6 months of the year from 26 to 36 minor storms.

And costs increased in line with it from $25 million to about $36 million.

The majority of this was in NYSEG's territory.

First half wind production was about 13% below expectations, of which 7% was wind resources.

Now as we look to the second half of the year, there are a number of key risks and mitigation opportunities.

We're implementing best practices and operating efficiencies across the company as part of our Forward 2020+ plan.

In Renewables, we're assuming normal wind production for the second half of the year.

Our earnings may also be affected by the construction and timing of the COD for the wind projects and the sales and potential partnerships of renewables development projects.

Keep in mind, we said we will be looking at sales that would generate gains of between $0.05 and $0.10 a share.

In Networks, we're addressing cost recovery mechanisms for minor storms in our rate requests, such as (inaudible), thresholds, deferral of staging costs and funding for the minor storms themselves.

However, 2019 is still a year where we may be exposed to storm impacts.

So until we get new rates in New York and Maine to reflect that, we're going to be subjected to those storm impacts.

We also expect additional potential impacts due to regulatory outcomes, including the FERC ROE decision under current proposal of 10.41% as the base and a cap for incentives at 13.08%.

So this assumed about $0.06 impact in 2019.

Going to slide 8. Moving on to the highlights of our Networks business.

In New York, we filed 1 year rate cases for New York State Electric and Gas and Rochester Gas and Electric on May 20, requesting new rates effective in the second quarter of 2020.

We are requesting a 9.5% ROE on a 50% equity, and we're projecting a rate base of $5.1 billion for the year 2020 to 2021.

The filings also address staging costs for storms as well as our resiliency plan, which includes the full cycle of vegetation management program at NYSEG.

We anticipate this will be about an 11-month process with the final decision and new rates expected by April of 2020.

On Slide 9, significant achievements that are made with our $950 million New England Clean Energy Connect transmission project, which will deliver 1,200 megawatts of Canadian hydropower to the New England grid.

The project is on track to have all Maine state permits by the end of '19, and final project approvals by early 2020.

In June, the Massachusetts DPU approved a 20-year contract between Hydro-Québec and the Utilities, Eversource National Grid and Unitil and the starting price of that is a little over $51 a megawatt hour.

In addition, 3 legislative bills targeting the project were defeated in May.

Other stages of the approval process are underway at the Maine Department of Environmental Protection, the Maine Land Use Planning Commission and the U.S. Army Corp.

of Engineers with their decisions expected in the late 2019.

Our time line has construction beginning in early 2020 and the commercial operation by the end of 2022.

This is supported by our existing control of 100% of the rights of way with 73% in existing transmission corridors and 27% in industrial forest.

On Slide 10, in Renewables, we're successfully implementing our strategic plan with 763 megawatts of onshore wind projects under construction, on track to come online by the end of the year.

Our Patriot Wind 226-megawatt wind farm was purchased at COD in June of '19 right at the end of the month.

Also, we executed new onshore wind contracts for 192 megawatts year-to-date, which are not in the February 26, 2019, long-term outlook, with a new PPA for 140 megawatts for La Joya ll in New Mexico signed in the second quarter and a 52-megawatt extension of the Tatanka Ridge project in South Dakota, which was secured in the first quarter.

We replaced 22 megawatts of previous merchant capacity with a new PPA for the Mountain View III wind farm in California.

Moreover, we have increased our pipeline from about 15.4 gigawatts to 15.9 gigawatts.

This breaks down into 6 gigawatts of onshore wind, 4.9 gigawatts of solar and 5 gigawatts of offshore wind, which includes 2.5 gigawatts from our Kitty Hawk site as well as 2.5 gigawatts from our 50% share of Vineyard Wind leases off the coast of Massachusetts.

In addition, we're reviewing prospects for the optimization and monetization of our pipeline with various ongoing negotiations on asset sales and potential partnerships.

On Slide 11, you can see an overview of our renewable projects.

Since 2018, we've executed nearly 2,223 megawatts of contracts for new renewable projects, exceeding by 223 megawatts our baseline growth strategy through 2022.

By year-end, we expect only 1 gigawatt of wind to come online.

In addition, we have secured contracts for over 680 megawatts of wind and solar projects for commercial operation in 2020 and more than 550 megawatts to come online in 2021 and 2022.

On Slide 12, concerning the offshore business, as I said, we were recently informed that the Bureau of Ocean Energy Management has delayed the final environmental impact statement for our Vineyard Wind 800-megawatt offshore wind farm and joint venture with Copenhagen Infrastructure Partners.

While this is not unusual given the need to consider all the best available information, and really the landmark nature of the project, Vineyard Wind will be challenged to move forward in its current configuration if the final EIS is not issued approximately within the next 4 to 6 weeks.

Despite this, we remain confident that any remaining reviews can be concluded shortly and a final EIS released soon after.

Vineyard Wind is committed to working with BOEM and the Department of Interior throughout that process.

With favorable action from the federal government and the Massachusetts DEP, we will continue to target a commissioning date in 2021.

Meeting this time line enables Vineyard to capture the 24% ITC over the $2.8 billion investment and would accelerate the project's environmental and economic benefits to the region.

Now the project has recently completed other permitting milestones.

In May, the Massachusetts Energy Facility Siting Board approved permits for interconnection with the regional grid.

Vineyard also received regional development review permits from the Cape Cod Commission and from the Martha’s Vineyard Conservation Commission.

In light of the recent vote from the Edgartown Conservation Commission against granting an export cable permit, Vineyard Wind is pursuing an order from the Massachusetts Department of Environmental Protection superseding the decision.

In addition, we have now secured over 80% of the project supply chain, including monopile foundations, which will be manufactured and delivered by Sif.

We have further finalized contracts with Vestas to provide 9.5-megawatt turbines, with Prysmian for offshore cables, with Bladt for offshore substation, with Windar for transition pieces.

The remaining 20% are in the final stages of negotiations.

Now on Slide 13, Vineyard Wind also holds 2 lease areas for submission in the future RFPs, which can accommodate up to 1.5 gigawatts and 1 gigawatt, respectively.

These sites are owned jointly with Copenhagen Infrastructure Partners.

In addition, the Kitty Hawk lease area is 100% owned by AVANGRID Renewables, and it has a potential capacity of up to 2.5 gigawatts.

The potential growth of the offshore industry is significant.

Seven states now along the East Coast have communicated offshore wind targets totaling nearly 25 gigawatts.

Vineyard Wind has submitted bids into the Rhode Island renewables RFPs, with proposals of 200 and 300 megawatts.

The selection of that winning bid is expected by the end of July.

On May 17, Massachusetts issued a second offshore wind RFP for up to 800 megawatts.

While bids from 200 megawatts to 800 megawatts will be permitted, a 400-megawatt proposal must be included.

Bids are due August 16, with selection expected on November 8.

Connecticut released a draft RFP on July 1. The final solicitation is expected on August 15, with bids due on September 30, and selections expected in November.

Submissions must include at least one 400-megawatt proposal and include multiple bids.

We do plan to bid in both of the RFPs, and we're also watching for opportunities for additional lease options.

On Slide 14, I want to update you on our Forward 2020+ program, which is a companywide improvement and optimization initiative that we launched in 2017 to ensure that we're operating with best-in-class efficiency.

As I mentioned in the first quarter update, we partnered with external consultants to perform what we call the comprehensive mid-period assessment of our Forward 2020 Plan.

In doing so, we evaluate everything from our organizational design and service delivery models to our processes and governance structures.

Through this mid-period assessment, we have identified opportunities to mitigate costs and deliver sustainable growth, which we expect to provide between $70 million and $85 million in pretax savings for 2019.

Approximately half of the revenues in savings we achieved this year will continue beyond 2019.

Along with other long-term improvement initiatives, we expect to see annual sustainable run rate savings of $100 million pretax going forward.

To achieve these results in the short-term period of time, we're implementing really transformative changes across AVANGRID.

For example, we're closely managing discretionary spending and capitalizing more labor hours across the board because we're staying up with all of our capital spending right now, which we didn't do last year.

And we also through improved processes and governance systems.

Increased capitalization and spend management initiatives will represent about $40 million of pretax benefits for 2019.

We've already started to realize the benefits of these initiatives, although the real benefit of our spend reduction initiatives will hit the P&L in the second half of the year.

Additionally, in the second quarter, we successfully transitioned to a co-source model for our tax team, that will save more than $2 million this year and over $4 million each year going forward.

This change has now been implemented.

We've also invested in O&M projects for our renewables fleet have already brought our wind availability up to 97% or better, which we estimate will add more than $2 million to our bottom line this year as well.

At the same time, we're becoming a flatter, more agile company by widening managerial spans of control and reducing layers in our organizational structure.

The efficiencies achieved here will provide about $5 million in pretax savings for 2019.

We're also in the early stages of implementing robotic process automation projects, which I mentioned in the first quarter.

Now we're automating processes in our billing, front office, credit and collection departments, which will both reduce our costs and enhance service for our customers.

For the longer term, we're building on the sustainable projects being implemented now.

We're reviewing further outsourcing, but also in-sourcing functions.

We will be moving work to the appropriate skill level.

Rather than using higher-priced and higher skilled contractors, we can in-source these activities more cost effectively.

We're optimizing renewable operations and reducing dry fans for our utility personnel to improve productivity.

These are just a few of the examples of the important projects we have come out of this mid-period assessment of our Forward 2020+ plan, and we're confident that revenue and efficiencies we will realize through this program have us on track to meet our goals and commitments.

In conclusion, we're implementing the strategy we put in place.

We're focused on our core regulated and contracted businesses and we continue to maintain a strong balance sheet, while we execute programs like the Forward 2020+ for best-in-class operational efficiency.

We will continue to focus on delivering clean energy solutions as we build the grid of the future and take care of our customers through excellent service and ever-smarter energy solutions.

We're fulfilling our strategy to deliver sustainable growth by investing in a smarter and cleaner energy future.

So now I'm going to hand it over to our CFO, Doug Stuver.

Thank you, Jim.

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

I'm now on Slide 17.

On this slide, we roll forward to earnings per share quarterly and year-to-date through the first half from 2018 to 2019 on a U.S. GAAP basis and on a non-U.

S. GAAP basis.

Adjusted earnings per share reflects the exclusion of mark-to-market adjustments in the Renewables segment, restructuring charges and adjustments related to our prior ownership of Gas Storage and Trading businesses, which we exited in 2018 and other items, the combined impact of which was negative $0.03 for the quarter and first half.

As you can see on both the U.S. GAAP and adjusted basis, Networks' results for the quarterly and year-to-date roll forward are lower, largely reflecting nondeferrable minor storm and staging costs and higher depreciation.

Our pending rate cases in New York and Maine will compensate for the higher depreciation once rates become effective for those jurisdictions.

We estimate New York rates will become effective in late April 2020 and Maine rates will become effective in October of 2019.

Renewables' results were also lower on a comparative basis, although a significant portion of the year-over-year decline occurred in the first quarter due to poor wind resource and negative impacts from extreme weather.

The poor wind resource continued in the second quarter, although improved from the second quarter of 2018.

Corporate results are lower in the second quarter comparison, reflecting the issuance of a new green bond as well as the impact of the consolidating tax rate adjustment.

I also want to add that we're on track with AVANGRID's 2019 capital plans.

In the first half of 2019, we've spent nearly $1.4 billion in CapEx, which is over an 80% increase to the first half 2018 levels.

This significant increase in investments is important to our future growth and in delivering safe and reliable service to our customers.

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

Slide 18 summarizes the results and key drivers for the Networks quarterly and year-to-date results and comparisons for the same periods in 2018.

For the second quarter, you can see that Networks' results were down $13 million quarter-over-quarter with $66 million of adjusted net income and $0.21 earnings per share.

While we experienced the benefit of $0.03 quarter-over-quarter due to new rate years in several of our utilities, this benefit was offset by a $0.04 negative impact from higher depreciation due to increased fixed assets placed in service as we successfully executed our capital investment plan.

Nondeferrable minor storms and staging costs were higher than the second quarter in 2018, particularly with higher staging costs in the latter half of the quarter.

We're addressing these impacts and our pending rate case filings in New York and Maine.

For the first half of 2019, the adjusted net income in Networks of $267 million was $13 million lower than the same period in 2018, with all of this difference arising in the second quarter.

Now moving to Slide 19, we provide the results and key drivers for the Renewables quarterly and year-to-date results and comparisons for the same periods in 2018.

As I mentioned earlier, our Renewables segment was a key driver for the year-over-year decline in earnings, although the quarter-over-quarter decline was much smaller due to several offsetting factors.

Quarter-over-quarter Renewables adjusted net income declined $4 million or $0.01.

Wind production was approximately 3% higher quarter-over-quarter.

However, wind production showed a flat earnings impact in the quarter-over-quarter change because we saw higher production in the lower-price merchant facilities and lower production in the higher-priced contracted facilities with the 2 impacts offsetting one another.

Renewables' results were negatively impacted in the second quarter by pricing, largely driven by the change in status of projects that moved from contracted to merchant, including the FirstEnergy Solutions bankruptcy effects that occurred in 2018.

Consistent with our expectations, PTCs are rolling off with a $0.03 negative impact for the quarter but will be replaced with new PTCs as the Patriot Wind project and 763 megawatts of assets under construction go into service later this year.

We're also showing a $0.08 positive impact quarter-over-quarter in the other category.

This contains a number of items, including minority interest, a $0.04 onetime benefit from a change in methodology for calculating asset retirement obligations and a small gains related to last year's sale of transmission service rates.

The gain from sale of last year's transmission service rates is approximately $0.01 and was tied to meeting certain milestones that occurred this year.

Impacts for the year-over-year comparison are similar and significantly impacted by the very low wind production in the first quarter.

Partially offsetting these impacts are the first quarter Klamath optimization and trading margins resulting from higher prices and volatility in the Northwest with the exceptionally cold winter as well as the ongoing impact of the repair of a Canadian pipeline rupture.

Now moving to Slide 20, we show Corporate quarterly and year-to-date results in comparison for the same periods in 2018.

The Corporate segment reported a negative $29 million of adjusted net income or $0.09 per share negative.

This is a $0.03 per share decline quarter-over-quarter primarily reflecting the $750 million green bond that we issued in May at an interest rate of 3.8%.

The first half year-over-year comparison also included positive tax impacts of approximately $0.05 due to a first quarter positive discrete tax item and a favorable year-over-year change in the consolidating tax rate adjustment.

AVANGRID's consolidated effective tax rate for the first half was approximately 19.6% before discrete items and that's largely in line with the first quarter.

Now the next few slides show some further details on the factors impacting Renewables earnings performance.

On Slide 21, we showed some statistics on wind production for the first half of 2019 compared to the first half of 2018.

Some quick takeaways from this slide are lower production in the Mid-Continent and West and slightly higher production in the Northeast.

Overall, wind capacity factors are down 7% or 2.3 percentage points for the first half year-over-year.

Over the second half of the year, we're assuming a total of 8.7 terawatt hours of production with the third quarter representing the lower portion of that total due to the seasonality of the wind resource and the additional wind resources coming online mainly in the fourth quarter.

Now moving to Slide 22, we provide some details on pricing trends.

Our overall average prices declined by 8% for the first half of 2019 compared to the first half of 2018.

This reflects a number of factors, including the expiration of PPAs where we rolled the project revenues into the lower-priced merchant market, the change in status resulting from last year's FirstEnergy Solutions bankruptcy as well as declines in merchant and REC pricing.

Merchant and REC pricing declined by 19% for the period with merchant prices declining primarily in the West during the second quarter and REC revenues declining in the Northeast and Mid-Continent.

Now turning to Slide 23, we included a slide this quarter to demonstrate our hedging strategy, which is to minimize our price risk by contracting for new projects and recontracting our hedging for projects with expiring PPAs.

In combination, we target approximately 75% to 85% of our generation output to be covered by PPAs or hedges.

You can see in the slide that our combined PPAs and hedges start -- the range of those start at 80% in 2019, 78% in 2020, 74% in 2021 and 70% in 2022.

All new projects going into service in 2019 are contracted and included in this graph.

However, the new projects going in service between 2020 and 2022 are not included.

Those projects all have PPAs and therefore will increase the portion of the portfolio covered by PPAs and hedges.

All expirations of existing PPAs and hedges are already reflected in this graph, and we've not included new short-term hedges that we expect to enter into as we move through time.

I also want to note that we did not include PTCs as a hedge for purposes of this reporting.

Some argue that PTCs because of the size of the funds received from that, should be counted as a hedge.

We take the more conservative route and did not include those in our measurement.

Now on Slide 24, we show our revised guidance ranges for 2019 of $2.18 to $2.28 for earnings per share under GAAP and $2.25 to $2.35 for adjusted earnings per share under U.S. GAAP, and those are further broken down by business segments.

For Networks, we're lowering the top end of the range by $0.03 to reflect the continued costs we're seeing related to nondeferrable minor storms and staging costs, plus anticipated negative impacts from resolution in New York for our 2018 storm proceeding partially offset by benefits we expect from our Forward 2020+ mid period assessment process.

This range continues to assume a favorable resolution in 2019 of the pending FERC ROE decision, which is estimated at $0.06 in our guidance.

In our Renewables business segment, we're bringing down the top end of the range by $0.02 due to low wind resource and weather in the first half of 2019, which was $0.09 below expectations and anticipated impacts from delays in COD of our 2019 projects, although we expect benefits from the Forward 2020+ process to partially mitigate these impacts.

This range continues to assume a benefit of $0.05 to $0.10 per share related to asset sales and partnerships and I'm happy to report that wind resource through yesterday is in line with our expectations.

So we're off to a good start for the third quarter in Renewables.

Finally, we adjusted downward the upper end of the Corporate range by $0.01 to reflect lower intercompany interest income from the Renewables and Networks segments.

That said, it's also important to acknowledge that our performance versus guidance over the remainder of the year has risks and opportunities, as Jim noted earlier.

Now on Slide 25.

This slide demonstrates that our credit ratings remain strong and we highlight the recent upgrade of CMP to an A rating by S&P.

Our dividend policy remains unchanged, targeting 65% to 75% of net income.

And as Jim has noted, the Board recently approved a $0.44 per share quarterly dividend, payable October 1.

On the next slide, we wanted to highlight that we continue to pursue our sustainability objectives and green financing strategy and have executed a $750 million green bond in May.

This was our second green bond, and we now have a total of $1.35 billion in green bonds outstanding, and that's in addition to our $2.5 billion sustainability-linked credit facility.

We recap that we've made ambitious and sector-leading carbon-reduction pledges, including a target of carbon neutrality by 2035.

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

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

So maybe the first question on the wind capacity factor just so we understand.

On Slide 21, when we look at the second quarter wind capacity factor, it looks like it's pretty close to the expectation or what you have in the estimate of around 34%.

Is that a fair way to understand how the wind performed in Q2?

Yes, I think in the second quarter, Praful, we saw the wind was actually down, off about a little over 3%.

Overall, our production was off about 9%.

So the wind actually was better, but we had something, the new construction we had and this is against our expectations.

The new construction we had, like for Patriot Wind, we assumed it was going to begin in May and that was a project that we were buying at COD.

Well, there were delays related to mainly weather in Texas because of the very wet spring and it caused construction delays, and we actually saw this at our Karankawa site as well.

So that cost us about 4% of the new construction, but the wind resource was a little better.

We have maintenance, that always contributes a little bit and then other external factors, but -- yes, the wind resource was really off about 3%.

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

No.

I think that's absolutely right.

And of course, it's regional.

We definitely saw lower wind in the Midwest region that persisted, but it was up relative to the other regions from Q1.

Got you.

That's helpful.

And just it sounds like Q3 is off to a better start, so the belief that your updated way to approach expected capacity factors for the wind resource are still reasonable is fair?

Yes, I think what we're updating and saying right now is -- I don't know Laura, do you have -- on the capacity factors, I mean we're looking at almost 31% for the first half.

Keep in mind that the third quarter is our lowest quarter for production, and the fourth quarter kind of is above that.

It's becoming a little better, but -- so Laura, anything else?

No.

I think that's exactly right.

I think Doug mentioned that we are forecasting 8.7 terawatts for the second half of the year and that does represent our historical life-to-date, which when we talk to our experts, that really does remain the best way to estimate wind production.

Got you.

And then just quickly following up on the sales and partnerships.

Clearly, that's $0.05 to $0.10 as you mentioned for 2019.

How has the progress been on that?

Has the interest level continued to be good in terms of the ability to sell these development projects?

And when should we hear something more on that front?

Yes, the progress is going along okay.

We're seeing quite a bit of interest in activities with partnerships and looking at development project opportunities for sale.

So we're pretty optimistic.

I would expect it's -- probably it's going to be the latter part of the third quarter, if not the fourth quarter before we'll have something to talk about.

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

Can you hear me?

Yes, we can.

Wanted to clarify here just in terms of the cost savings and how you think about the sustainability of those going forward?

Maybe even as you think about them being a run rate into the next year.

I know we're not quite at the guidance conversation yet for '20, but just want to have a little bit more of a context as we roll forward here.

Yes, we looked at it that what we're doing this year, a good chunk of it is just reducing budgets and cutting costs.

But we feel that what we're having -- seeing this year, about 40% of that's going to be sustainable going forward and we see a run rate, as I said, of about $100 million into 2020 of savings and additional revenue efficiency.

However, you want to characterize it, we see it being around $100 million into 2020.

So there are different -- added things that we're working on right now that we're not going to get the benefit until we get into 2020, such as robotic automation.

Those type of things we're building the software now to be able to implement that, which will give us savings in processes and the technology is going to improve things for us.

So that is one example.

So we're looking at about 40% of what we can do now and then -- will be sustainable, then we're going to add to that and -- throughout this year so that when we hit 2020, we should see a run rate of about $100 million.

Got it.

Okay.

Fair enough.

Now if I can move back, I think you said it was 19% decline in merchant and REC, can you give a little bit more context on where you're seeing that and again, just to kind of ask that question, how do you think about that rolling forward here, especially given your updated disclosures here on Slide 23?

If there's any good way to describe that in aggregate kind of a net impact going forward.

Yes.

You're talking of pricing changes year-over-year, correct?

Yes, yes.

And how you see that kind of manifesting itself on a go-forward basis given the hedge update?

Sure.

I think Slide 40 is helpful, Julien, for that.

We detail in there by region for the price changes that's happened year-over-year, and you can see in the Northeast and particularly with RECs, we saw a big decline in pricing there.

With merchant prices, we saw in the West a fairly sizable decline as well.

So as far as the forward-looking view, I think probably Laura, you might be best to comment on...

And maybe let me clarify too, I mean because I see the Slide 40, but how do you think about that sort of manifesting in your own results, i.e., where are you disproportionately hedged or under-hedged, or however you want to think about taking these merchant numbers and translating it back into your -- the exposures that we should be thinking about on an open basis?

I.e., what is the unhedged piece maybe is the better way to ask that as you think about '20 to '22?

Well, when we look -- yes, Laura, go ahead.

No, go ahead, I was going -- I can kind of walk you through just overall our hedging strategy if that's helpful.

In the WEC, our merchant capacity is primarily in the Northwest and we manage this merchant capacity as part of our Pacific Northwest portfolio, which, as you know, is part of a balancing authority.

We have a hydro slice, we have C&I customer load that we're managing.

And so the depths of the mid-sea market really does allow us to actively hedge that out into the curve.

In ERCOT, we typically have not sold forward fixed price against variable wind just due to the $9,000 per megawatt hour price cap.

However, we have recently entered into volumetric swap transactions, and this will allow us to firm up that generation and just provide us some additional flexibility to further hedge there.

Outside of that, I think you're aware we've utilized natural gas to hedge our Gulf Coast merchant wind there.

In the Midwest, from our perspective, the market hedges are illiquid and effective -- ineffective.

And really it's because Midwest prices are and just continue to be so low.

Often we see them in the high-teens.

And so market hedges at this level really don't protect any downside, but they limit all of your potential upside.

And so we really don't have much hedging activity there.

In the Northeast, I break it out really into New York and to PJM.

In New York, our assets are in Zone E, and this pricing zone is really illiquid, and if we tried to hedge with an alternative zone like A or G, it creates more basis risk than the existing price risk.

So that's why those remain unhedged.

In PJM, most of our price risk is correlated with hubs that are fairly liquid for 10 years inside of a year, but the liquidity really decreases when you get out further in the curve and that's why we keep those to shorter-term hedges.

Does that help, Julien?

Please.

So maybe what I'm -- just to clarify that, the updated volumetric swap transactions that you just talked about for ERCOT, that's already reflected in the '20 to '22 outlook, right?

Yes, those are 1 year hedges right now, the transaction swaps are.

Okay.

Yes.

That's short term, Julien, and we just did that recently, I think within the last couple of months.

So -- and it was more we were testing the market to see how it actually would perform, and we're using just one of our wind farms.

So we wanted to make sure that it was going to work as effectively as we thought it would.

And so it's more of a test case, and we're seeing that it actually is proving to be rather effective.

Got it.

Okay.

So I think we got a good sense on where you got the exposures.

Our next question comes from the line of Christopher Turnure with JPMorgan.

Jim, could you give us a little bit more color on the BOEM permit comment that you made?

I think your original expectation was that you would get the final EIS by 2Q and then actually get the approval from the agency by 3Q, and you're saying now within the next couple of weeks, you expect a certain component of that, but if that doesn't happen, then the plan could shift out?

Yes, what we said originally, we had worked with BOEM to get the -- they were going to issue the permit or at least the final EIS early in July and then get -- the record of decision would have come in August.

It's been delayed right now, but we're still working with them and pretty confident that we can get something done by the end of August and that will keep us on track with our time frame.

So that was the time frame we had, and like I said, we're working with them right now.

Okay.

And is there another kind of date we should think about where you would only delay the project by a matter of weeks or months if you didn't get the permit by that date?

Well, I think what we said was it would be challenging to move forward if we don't get the final EIS in the next 4 to 6 weeks.

That having been said, it doesn't mean the project is dead by any stretch.

It just means we're going to have to reconfigure things or do something differently.

So Laura, do you want to add anything to it?

No.

I mean I think to your point, Jim, really right now we are absolutely focused on getting to resolution under the current configuration and maintaining to the current schedule.

If we're required to, I think we'll look at other alternatives, but really our focus remains on maintaining our current schedule and working through these issues.

Okay.

And then my second question is on the dividend.

I think last July, in the middle of the month, you had done your first dividend increase in a number of years and you mentioned that payout in absolute dividend should go up roughly in line with EPS growth given your long term 8% to 10% EPS growth guidance is kind of maybe to pause last week.

A pause or is it a change in dividend strategy?

No.

There's no change in the strategy.

It's just looking at what is the best timing for an increase, and looking at dividend changes and making sure we're within the 65% to 75% payout ratio that we're looking at going forward.

So this year, with our guidance, we're not quite there and so we want to have the Board look at it and we'll probably review it quarter-by-quarter now going forward.

But no change in the philosophy or policy.

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

Just one follow-up question to the Forward 2020 cost savings plan.

Any rule of thumb on how we should break up those savings among the various segments and also just longer term your ability to keep those savings, especially at the Networks segment?

Yes.

I think if you look at it, at least this year, it's about 35%, 40% is in the Networks and 30-plus percent in Renewables and Corporate.

So it's kind of split almost evenly among the 3. Going forward, it's our -- as a public utility, it's our obligation to operate as efficiently as we can.

And 2019, we'll be able to retain the savings.

Going forward, it's going to -- we'll be working with the staff of the commissions to figure out what gets flowed through and what doesn't.

They will set rates based on some assumptions and then we have sharing mechanisms too, primarily in New York and other jurisdictions, Connecticut.

That -- really, those are designed to capture these type of things, where if you start over-earning because of cost savings or other things, then they get -- it flows back through to customers.

So it's our job to make sure we're operating efficiently and that's what we're going to do.

The things in Corporate and then in Renewables, some of those savings, particularly Renewables for sure, I mean those flow to our bottom line.

In Corporate, some of those get allocated, some retained in Corporate and some go back to the different businesses, whether Networks or Renewables.

Understood.

And in terms of the minor storms and staging costs, so far this year, it seems like you're commenting that they are a part of the reason for the lowering of the top end of the guidance.

Does that mean that those storm costs are running above what you've already embedded when you gave the guidance in February?

Yes.

They actually are running a little bit ahead.

I don't know Bob, Tony, you guys want to comment on that?

Yes.

Sure.

This is Tony Marone.

So those costs are running above what we had previously thought.

They're running ahead right now by about $11 million.

We do have some offsets though that we're allowed to take that should reduce the exposure on that.

We have 2 issues: one is that we've got quite a more few more storms year-to-date; 36 storms and 19 minor storms, nondeferrable minor storms versus 26 in 2018.

So that difference plus a bit more aggressive staging to make sure that we're being responsive to the needs, particularly in New York.

So those are the 2 factors.

Understood.

And maybe one final one.

On offshore wind, assuming the offshore wind ITC rollout and I guess exploration is not extended, do you continue to plan for that couple of hundred bps over the cost of capital when bidding on future projects?

When we look at future projects, it depends on the time frame and when they could be operational.

And if the ITC -- we're assuming right now, it's not -- there's no provision for it to be extended beyond the current time frame, which I think is 2023, where it phases down -- phases out, actually.

So we will bid based on what the law is at the time and when we think we can get the project operational.

Our next question comes from the line of Angie Storozynski with Macquarie.

Questions.

Are you seeing any benefit from lower interest rates on your Corporate drag?

So you're issuing bonds seemingly at lower interest coupons -- on lower coupons than we had expected.

And I'm not seeing any change in the guidance for the corporate level drag.

Well, we are seeing lower interest rates than what we had anticipated.

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

Yes, I'd just add at the corporate level, though, we had hedged the 10-year treasury rate prior to issuance.

So basically, the all-in yield on that 3.8% coupon is a little under 4.5% and that was largely in line with our expectation risk.

When you look at, say, the Networks level where we also have some debt issuance, we are seeing benefits in that section.

We don't hedge the treasury rate for that portion.

Okay.

And just one other follow-up.

On the FERC ROE, can you elaborate again what this $0.06 EPS impact is and how it's embedded in the guidance?

The $0.06 would come from previously -- well, it's the change in the rate that we have for ROE, what we had booked against the modifications that were made and then what we had reserved in the past and then going forward, being able to then capitalize on the higher cap rate that we would see, which is the 13.09% versus the 11.74% that's in place for a cap today.

So those -- there's a number of factors there that would enter into it.

But meaning this is -- again, this is just potential upside to your guidance?

Or you have a certain scenario already embedded in '19 guidance?

We have it in our guidance.

We have that $0.06 in our guidance, yes.

Our next question comes from the line of Praful Mehta with Citigroup.

I just had a quick follow-up question.

In terms of the cost-saving initiative, which you've already touched on, just want to understand how much is in the plan right now and how much is incremental?

In the plan for this year, Praful, we have $70 million to $85 million for this year, for 2019, and most of that is in the second half.

Going forward, for 2020 and beyond in our plan -- our long-term plan that we put out in February of this year, I don't believe we had any savings in there.

Got you.

So anything incremental that you have as a run rate that you've talked about in the presentation that is incremental to the plan that you've already presented?

Yes.

But keep in mind that a lot of that when you look at savings we get will allow us to reach -- be able to hit the ROE targets we have or maybe exceed them.

So keep that in mind as you're looking at it.

Sorry, just so I understand, the -- I'm assuming that the plan already had some ROE assumption in there, and so are you saying that this would -- this saving would help you improve on that as in get to the upper end of it, or just so I understand how you're characterizing the benefit on a long-term basis?

In the plan for the long term that we put out in February, we assumed we would earn at the allowed ROE levels only for every jurisdiction going forward, and this would be 2020 and beyond, not 2019 because we knew we were going to file in New York.

So this will aid us in getting to the allowed return if not going a little bit above that depending on how we manage things.

It also isn't just in Networks, it also applies to Renewables as well.

So a chunk of that, probably 30% is Renewables-oriented, just as about 30% is Corporate.

So a lot of those -- a little different than what you might have expected.

And those would be incremental to what we had in the long-term projection.

Yes.

All right.

And those incremental piece is obviously there's no giving back that piece.

So those should be more sustainable and should show up as incremental upside versus the plan?

Those 2 other pieces?

The non...

Yes, for Renewables and the Corporate portion that gets allocated to Renewables.

Yes.

We have a follow-up from Julien Dumoulin-Smith of Bank of America.

This is [Alex] for Julian Dumoulin-Smith.

I just had 2 quick follow-up questions.

First on Networks, I was wondering what the impact of billing issues in Maine is on your expected authorized ROE?

And then my second question is if you could provide any more details on that $0.08 positive impact in Renewables related to the onetime items and the asset retirement obligation adjustment?

Kind of maybe what we should think about going forward with that $0.08 impact?

Yes.

[Alex], in Maine, the commission staff came out with a bench analysis.

Came out to say that they were recommending a -- I think it was a 75 to 100 basis point reduction in the ROE to reflect the issues around the customer service that happened.

So if you take that into consideration, then it would be for the time.

I think they said it would be for 1 year until -- to demonstrate that we had improved on and gotten things back on track.

I don't know Tony about you?

Yes.

No, Jim, I think you characterized it well.

The bench analysis, which is a recommendation of staff based on the discovery so far made that recommendation.

There were 2 bench analysis that occurred and both retained that recommendation for that 75 to 100 basis point reduction, and it was for a period of 12 months of demonstrated improvement in performance, whereby which there could be a mechanism for us to refile for new rates.

The case is underway and a matter of fact, hearings in Maine start today and are occurring this week.

So this is a preliminary recommendation from staff and we still have a long way to go on this case, but right now, the decision is expected for October, and so there's still some more time on this.

And I'll say that the -- many of the metrics that the staff focused on, in particular, the speed of answer on customer calls, those metrics we have been meeting throughout this year.

So I think we've made very good progress prospectively.

It's now just a question of how do we deal with the pieces associated with it.

I mean these issues are really issues that came about in the winter of '17-'18 and then through calendar year '18.

Doug, do you want...

So, yes.

On the $0.08 positive impact in the other category for Renewables, that really breaks down $0.04 for the change in the methodology for calculating asset retirement obligation.

That's a onetime item.

We had about $0.01 impact from the gain on sale of transmission service rights that took place last year.

So you could think of that more as part of, say, the $0.05 to $0.10 benefit from partnerships, sale of development projects, et cetera.

And then we also had a $0.03 positive impact.

That was the change in minority interest.

That's a function of our tax equity financing that we have in place and that's more of an ongoing item.

Okay.

If I can, just one more quick follow-up question on Networks.

I was wondering what your thoughts are on just the New York Commission in light of potential Con Edison read-throughs with the lower ROE.

Do you think that, that indicates there is a risk that your ROE, I know you filed for 9.5% that, that could be a little bit lower?

Well, I think if you look at the last 3 or 4 cases, the ROEs have generally come in around 9% with a 48% equity ratio.

They vary a little bit and someone got a 50% equity ratio but then they got a slightly lower ROE than 9%.

So the staff positions have been lower than that, in the mid-8s at that time.

So I think that's probably from what we're seeing a reasonable area to focus on, that kind of 9%, 48% equity.

Our next question comes from the line of Martin Young with Investec.

Couple of questions.

One is just a clarification on your second half expected output from the Renewables asset.

Did you say 8.7 terawatt hours?

And the second question then relates to comments that IBERDROLA were making this morning on their results call in respect of an acceleration of the capacity buildout between now and 2022.

They have given a pretty clear indication that they expect to be increasing that at next February's Capital Markets Day.

Just wondered if you could give some comments on what type of increases if any, we could be seeing from yourselves?

Yes.

Going forward, we will be redoing our forecast and talking about it at our Investor Day in February.

So we're not going to be talking about anything at this point in time.

And just to add, I think we've heard on all of IBERDROLA too, so you got to think about what they're saying.

But we haven't modified our forecast at all.

And the 8.7 terawatt hours that is what we said and our expectation for production for the balance of this year -- second half of the year.

But I mean just directionally on the capacity, would it be an increase?

This is what you said in February given that you've obviously got some new apps already disclosed today?

No.

That was our estimate, and we haven't modified it.

We were assuming normal wind production and the introduction of the new capacity that we also had projected, now most of that will be at the end of the year.

No.

I'm talking about the aspirations between now and 2022.

Directionally, would you be moving upwards given that you have added a couple of additional projects year-to-date that weren't in the February numbers?

No.

We have not modified our projections at this point.

Our next question comes from the line of Andrew Levi with ExodusPoint.

Actually, most of my questions have been asked and answered.

Just a few other things or follow-ups.

So just on [Alex's] question.

So just to understand what you have built in guidance.

So in your 9% to 10% growth rate going forward, did you assume that your ROE would stay constant at where it is today?

In our -- we never said, Andy.

In the 8% to 10% growth we put out in February this year, we just said we would earn the allowed returns whatever they ended up being (inaudible).

But I will say if you look at rate base growth, it's about 9%.

It's consistent with the growth rates that we talked about.

You assume ROE is (inaudible).

Because I think ConEd and their staff got like an 8.3% ROE, so people are thinking like 8.7%, so...

Yes, and that's not surprising.

I think as Bob was mentioning, the staff always comes in a little lower.

Okay.

And then just on Maine, so you do have this billing issue.

Could you just talk about that a little bit more?

I mean there's been so much stuff in the press, we get articles every day on it.

Like can we just get kind of your opinion on it and kind of what happened and the financial impact, if any, to you?

And also whether there'd be any refund to customers?

It's just you read all this -- so beyond the ROE potential hit and -- what penalties, if any, are possible and how should we think of it on a financial basis for you guys?

Yes, when you look at the billing, we did our own internal audits and reviewed the billing system from the meter, all the way to the bill.

They hired a -- the commission hired a firm to do a forensic audit of the billing system and concluded that it was billing things correctly.

The issue really more is, for us, is the customer service and the fact that we didn't provide the customer service that our customers expect or that we should be delivering.

And so when we look at it from that standpoint, that's where we really fell down.

And now people look at the bills and say, well, the bills are very high.

Well, we had a very cold winter, every individual has different circumstances and we need to go through every one of those and work with the customer to make sure they understand what occurred, what happened, and so that they can have confidence that actually their bill was correct.

In many cases, we didn't -- some of it was our fault; we didn't bill for a couple of months for whatever reason.

Customer didn't -- maybe didn't pay the bill on time, so they had double bills.

I mean there were all kinds of different circumstances.

And we got to work through that with each customer to make sure they understand and they can have confidence.

So Tony and Bob, you can add to it?

Jim, I think you characterized it extremely well.

The most important thing is that the metering and billing systems are producing accurate results.

The other issues with the implementation of the system and the amount of estimated bills and so forth and the complications associated with that and our inability or our delay in being able to respond to the amount of customer requests that were associated with those changes was significant.

But the billing system and the metering system, as we have checked that, not only with our own internal audits but with independent audits and then now there's really an audit out of the audit that is occurring as well.

And so far, all of those things are continuing to support the fact that the billing system is working properly.

So we've got several things in place underway right now to improve the customer service for customers and the responsiveness.

But at the heart of it, the system is working properly.

Great.

That definitely explains that.

And then just my last question, again more kind of looking forward.

So you guys have done a great job with this 2020+ program, coming up with $100 million of savings.

I guess a portion will go back at some point to the ratepayer, which is good for the ratepayer as well.

But just to kind of understand, kind of -- again, I know you haven't given guidance for 2020, just the growth rate.

But I guess this year, you have the $0.08 you had in the second quarter, you had some tax optimization in the first quarter.

You're going to have some asset sales in the third or fourth quarter.

And then if the FERC decides to rule on your ROE issue, that will also give another kind of one-timer as well.

So let's call it, like, $0.25 to $0.30 of one-timers, and then a portion of that -- and then at the same time, you're getting $75 million to $80 million of cost savings, which probably was envisioned into next year, but it carries into next year because I don't think it was part of your guidance for this year originally, but I think after the first quarter call, it became that.

So you have all these kind of onetime things kind of dropping off to next year.

It kind of gets offset -- a portion of it gets offset by the O&M savings and hopefully normal wind production.

But then at the same time, you also have lower power prices, which we just don't know what's going to happen there, but right now are very, very low.

So how do you kind of bridge into 2020 and kind of make up these one-timers?

Obviously, you have a rate case and all that, but it seems like your ROEs are coming down.

So can you give us -- kind of talk at a very high-level because I know you haven't given guidance, how you kind of offset $0.25 to $0.30 of one-timers that you used this year to make up for some issues that you had?

Yes, Andy, a couple of things: one, when you look at it, we said we would be looking to have asset sales and really redeployment of capital, let me put it that way, and it's probably going to result in $0.05 to $0.10 per share on a continuous basis.

So we're going to keep working on redeploying our capital and optimizing our portfolio.

So that's going to be ongoing.

That's not something that's just going to be one time for this year is the way we see it.

Secondly, the $100 million we're talking about for efficiency savings going forward, that is also going to be helpful in making sure that -- give us some flexibility, give us some room to be able to make sure we get the growth we're looking for.

So those are 2 areas that I think we need to focus on.

And then you touched on this, Andy, as well, but I think if you look at Networks and our performance this year, I mean when we set expectations, it was as we talked about based on earning the authorized return except for in New York, where we knew we had a 1 year stay-out period and there would be costs that we'd be incurring that would put a drag on ROE for this year, but would be recouped as we get new rates next year.

And certainly, you're seeing in the results for the first half, depreciation is a big part of that.

As Jim mentioned, we're on target this year with our capital program consistent with expectations for this year and our long-term outlook.

There's depreciation attributable to that, that we're eating and absorbing for this year that will go forward.

But also on the staging and minor storms, there's clearly a higher expectation on the part of customers, local community leaders, our regulators, politicians as it relates to response to storm restoration.

And I think last year, we, quite frankly, early in the year somewhat struggled with that, but we've done a good job this year ensuring we had the right resources, be they our own resources or contractor resources to be able to respond to storms.

I think we've done a very good job this year on that.

Obviously, that comes somewhat with a cost.

And in our filing that we made, we're looking to adjust the recovery mechanisms not just for major storms, but for minor storms and staging costs so as to recover those costs.

So I think you will see the ability with the next rate case to be able to recover those costs that we're currently incurring that we aren't getting in rates as we speak.

Our next question comes from the line of Reza Hatefi with LNZ Capital.

Just I was -- sorry, maybe you addressed this earlier.

I was just a little confused.

The Forward 2020 cost cuts, they were originally not part of 2019 guidance when you gave it in February, but then on the first quarter, it started rolling into numbers.

I'm a little confused on how -- the sequence of that.

No.

We had something in 2019 for savings.

We just weren't explicit about how much and we didn't have anything in 2020 and beyond.

Okay.

So when you gave -- originally gave 2019 guidance in February, there was some embedded in there, but you just weren't explicit?

There was some, yes.

At this time I'm showing no further questions.

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

Okay.

Well, thank you, everybody, for participating today.

Hopefully, you've got a little more insight in what we see for the balance of this year and we'll be talking to you in the future.

And if you have further questions, please don't hesitate to contact our Investor Relations team.

So thank you.

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

That concludes the conference.

You may now disconnect.

Everyone, have a wonderful day.