Vistra Corp (VST) 2017 Q4 法說會逐字稿

Good morning.

My name is Chris, and I'll be your conference operator today.

At this time, I would like to welcome everyone to the Vistra Energy 2017 Results Conference Call.

(Operator Instructions) Thank you.

Molly Sorg, Vice President, Investor Relations, you may begin the conference.

Thank you, Chris, and good morning, everyone.

Welcome to Vistra Energy's 2017 Results Investor Conference Call, which is being broadcast live via webcast from the Investor Relations section of our website at www.vistraenergy.com.

Also available on our website are a copy of today's investor call presentation, our 10-K and the related earnings release.

Joining me for today's call are Curt Morgan, President and Chief Executive Officer; Bill Holden, Executive Vice President and Chief Financial Officer; Jim Burke, Executive Vice President and Chief Operating Officer; and Sara Graziano, Senior Vice President of Corporate Development.

We also have a few additional senior executives in the room to address questions in the second part of today's call as necessary.

Before we begin our presentation, I encourage all listeners to review the safe harbor statements included on Slides 1 and 2, which explain the risks of forward-looking statements and the use of non-GAAP financial measures.

Today's discussion will contain forward-looking statements, which are based on assumptions we believe to be reasonable as -- only as of today's date.

Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied.

Further, our earnings release, slide presentation and discussions on this call will include certain non-GAAP financial measures.

For such measures, reconciliations to the most directly comparable GAAP measures are in the earnings release and in the appendix to the investor presentation.

I will now turn the call over to Curt Morgan to lead our discussion.

Thank you, Molly, and good morning to everyone on the call today.

As always, we appreciate your interest in Vistra Energy.

I would like to begin our discussion today on Slide 5 of the presentation that we provided with a brief highlight of our 2017 financial results.

For full year 2017, I'm pleased to announce that Vistra Energy delivered adjusted EBITDA of $1.455 billion.

This is in the top quartile of our narrowed guidance range, reflecting very strong business performance by our operations teams and tenacious cost containment across the organization in the face of significant headwinds during the year, including persistent mild weather and a 2-month unplanned outage at Comanche Peak Unit 2 during the summer.

Adjusted free cash flow for the full year was $831 million, which was roughly a conversion ratio from EBITDA to cash flow of almost 60% and was right in the middle of our narrowed guidance range, demonstrating the stability and significant drop-down of cash from EBITDA delivered by our low leverage, low-cost integrated model.

In fact, our business model converts substantially more EBITDA to free cash flow than other commodity-based energy businesses, reflecting the relatively lower capital required to sustain our business and our focus on lower leverage.

We believe this is a key differentiator for Vistra and one that investors and analysts will begin to recognize and focus on.

For Vistra Energy to deliver these strong financial results in the face of such significant headwinds throughout the year demonstrates the resilience of our business and the dogged focus of our company on maximizing shareholder value.

I would like to point out a few key highlights in 2017.

We identified run-rate EBITDA enhancements of more than $50 million through our fossil fuel operations performance initiative or what we call OPI.

It's impressive given that these results were achieved on the remaining generation fleet after the retirement of 3 large coal plants where improvements were of paramount focus and importance.

As you know, a similar OPI process is currently underway at Comanche Peak, and we plan to capture the benefit from that process as part of our merger synergies and our OPI process going forward.

In total, Vistra realized approximately $28 million out of the $50 million run-rate EBITDA uplift in 2017 from these operational improvements, which helped us to achieve our strong 2017 financial results.

Somewhat forgotten in all of our business activities since emergence from bankruptcy is the implementation of our support organization restructuring, which occurred largely in 2017.

This restructuring enabled us to take more than $340 million of costs out of the system, an increase of more than $40 million over our initial target, without disrupting service levels or compromising business operations, most notably safety.

We believe this is significant and real evidence that we know how to restructure organizations and follow through to not only capture our targeted savings, but to go beyond those targets.

In our view, this should bode well for our ability to carry through in our targeted value enhancements from the merger with Dynegy.

It is easy to talk about taking costs out of the system.

It's another thing to execute on it, and we believe we know how to execute.

On a cash basis, we reduced borrowing costs on our credit facilities by approximately $66 million on an annualized basis through various repricing transactions executed from February 2017 through February 2018.

We made several capital allocation decisions in 2017 as we continue to modernize our generation fleet through the acquisition of Upton 2, one of the largest solar projects in Texas, which remains on track to be synchronized to the grid sometime next month and achieve commercial operations in the summer.

And I will note that the Upton 2 project has very attractive integrated economics and will support our retail offerings in the future.

We also had the acquisition of the roughly 1,000-megawatt combined cycle plant in Odessa with access to deeply discounted gas supply in West Texas and which we fully integrated within 3 days -- or excuse me, 30 days of signing and almost immediately upon close.

Also on the generation side, in October of 2017, we made the difficult decision to retire nearly 4,200 megawatts of uneconomic coal plants.

Unfortunately, the economics of these plants and their related mines did not support continued investment in operations in what was an unprecedented low-power price environment.

All 3 of these plants -- Monticello, Sandow and Big Brown -- were retired as scheduled.

Going forward, we'll report all the financial results related to the reclamation and decommissioning of these sites in our new asset closure segment, which I will describe in more detail momentarily.

And finally, on October 30, 2017, we announced the execution of a merger agreement with Dynegy, creating what we believe would be the leading integrated power company in the United States, focusing on the key tenets of success: Low leverage; integrated operations with an emphasis on the retail customer; business execution; cost management; and disciplined capital allocation.

We believe we demonstrated these key tenets during a transformational and successful 2017, which should lay a strong foundation for 2018 and beyond.

Turning now to expectations for 2018.

While we have strong tailwinds for Vistra on both a standalone and combined basis with Dynegy following the closing of the merger, we will not be updating our 2018 standalone adjusted EBITDA guidance range this early in the year.

As you may recall, we announced an initial standalone guidance range of $1.3 billion to $1.45 billion and a standalone adjusted free cash flow guidance range of $600 million to $750 million.

I would like to highlight that our adjusted free cash flow guidance for 2018 includes approximately $70 million of nonrecurring Comanche Peak generator capital expenditures to replace the Unit 2 generator and create a spare generator for the site for the future.

Excluding this nonrecurring item, our adjusted free cash flow guidance range for the year would be $670 million to $820 million.

And as I just mentioned in 2018, we're also introducing a new reporting segment called the Asset Closure segment, which will track and measure the performance of our operations teams tasked with the job of efficiently decommissioning and reclaiming the plants and mines at our now retired sites.

While this segment will incur various retirement and reclamation costs for the next several years, those costs are expected to significantly decline over time and eventually would be wound down when these activities are complete.

As a result, both the Vistra management and Board of Directors have found it informative to view the Asset Closure segment as separate and distinct from Vistra's ongoing operations.

We also believe it is important to provide this incremental detail to you, our investors, to give you visibility into the performance and earnings potential of our ongoing operations.

While creating this new segment is very important to provide a better view of the ongoing earnings of Vistra and the wind-down of our reclamation activities, frankly, more important to me is the organizational focus we have created to maintain proper attention on our ongoing business operations and to separate out and to bring distinct focus to winding down our retired facilities and properties, which includes generating a revenue stream from scrapping and monetizing of the retired sites.

We expect this to be a profit and loss segment.

And obviously, we're going to try to minimize the costs and hopefully, reduce that as much as we can through scrapping and monetizing the sites.

It's also something we want to build a core capability around given the fact that when we close the Dynegy transaction, they also have sites that are closing, and we are likely to have sites that will close in the future and we need to be good at minimizing the costs related to exiting these sites.

As Bill will explain in more detail later on the call, Vistra expects its ongoing operations will deliver adjusted EBITDA of $1.35 billion to $1.49 billion and adjusted free cash flow of $690 million to $820 million in 2018, excluding the Asset Closure segment.

The adjusted free cash flow guidance range increases to $760 million to $890 million, when excluding the nonrecurring Comanche Peak generator CapEx.

Under any of the views that you take around this, the free cash flow conversion of our company is over 50%, and on the high end, it's almost 60%.

When valuing our business, we believe it is most appropriate to apply an EBITDA multiple or free cash flow yield to the guidance range of our ongoing operations as the asset segment exists merely to wind down the operations of our retired sites.

We expect to provide more information on the cost of wind-down of the retired assets coincident with the reporting of the Asset Closure segment starting with the first quarter 2018 results, which that call will likely be in early May.

And last, as you know, forward curves, especially in ERCOT, have improved in recent months.

And no potential benefit from that has been included from the curve uplift and is not reflected in our 2018 guidance ranges that we announced in the fall.

We plan to initiate guidance for the combined company following the close of the merger, and we expect to include that guidance initiation to update for forward curves, synergies and our OPI effort.

We are hopeful that this will coincide with our first quarter earnings call as we are cautiously optimistic the merger with Dynegy will be closed by then.

Moving to Slides 6 and 7. As the charts on 6 and 7 depict, both historical forward price curves as well as historical spark spreads have improved in recent months in nearly all the key competitive power markets in the U.S. ERCOT curves have continued to rise and remain materially above historical 2017 levels.

The same trends exist in -- for 2019 historical forward price curves and spark spreads as we depict on Slide 7.

While we are not yet providing guidance for Vistra pro forma for the anticipated merger, as I mentioned earlier, we believe the recent upward movement in the various forward price curves could provide tailwinds for the pro forma entity in 2018 and 2019.

Specifically utilizing December 29, 2017 curves, we estimate there could be upside for the combined Vistra and Dynegy businesses of approximately $100 million to $150 million in 2018 relative to the full year estimates included in our merger announcement presentation, and potential upside of approximately $100 million to $200 million in 2019 relative to Vistra management's adjusted EBITDA estimate for the combined company disclosed in the merger registration statement.

As of early February, forward curves in most markets outside of ERCOT have since come off their December and January highs.

However, we still believe there could be tailwinds to 2018 and 2019 financial performance as a result of recent power price and spark spread improvement, in particular, the continued and significant increase in ERCOT curves through February.

Perhaps more important, the forward curves continue to exhibit significant volatility.

It is this volatility that enables Vistra to create realized price curves that have historically been materially above settled prices.

Following the closing of the merger with Dynegy, we will be able to execute this hedging strategy on a larger fleet with tremendous liquidity above the PJM and ISO New England markets.

And so long as the curves continue to exhibit volatility, which we expect, and as they have done in recent months, Vistra will be well positioned to create incremental value for shareholders.

As you all know, gas prices have reflected softness in recent months due to associated gas from shale oil formations, and we continue to expect that gas prices will remain range-bound between $2.50 and $3.50 an MMBtu for the foreseeable future.

Despite this somewhat static gas forecast, we have recently seen material improvement in summer heat rates in ERCOT as a result of the forecasted single-digit summer reserve margins, which are well below ERCOT's target reserve margin of 13.75%.

It is this improvement in summer heat rates that is driving the improved outlook on the summer -- on the on-peak summer forwards in ERCOT.

While 2019 power prices and spark spreads have not improved as much as 2018, we believe the summer of 2019 in ERCOT could be even tighter than 2018, and curves will likely reflect this as we get closer to 2019.

It is important for us to note that following the merger, Vistra will be even less sensitive to gas prices than it is on a standalone basis.

This is due to the addition of Dynegy's sizable combined cycle fleet, coupled with the significant contribution of capacity revenues to the pro forma enterprise, which will better insulate Vistra from low gas prices as compared to standalone Vistra's predominantly coal and nuclear fleet located in the energy-only ERCOT market.

We estimate the merger with Dynegy will reduce our sensitivity to natural gas by about 12% to 15%.

This reduced sensitivity in natural gas is just one of the many benefits we foresee from the merger with Dynegy, which I know is a topic of much interest to you all.

On Slide 8, we'll move to the Dynegy merger upgrade -- or excuse me, update.

So let's go ahead and turn to Slide 8, where we have set forth a few key merger updates.

First, in early February, we received HSR clearance to proceed with the merger.

And last week, we received approval via consent agenda from the New York Public Service Commission, leaving only the shareholder vote, which I believe is on March 2; the FERC approval; and the Public Utility Commission of Texas approval.

As you know, both the Dynegy and Vistra shareholder votes are scheduled to come up, as I just said, on Friday, March 2. And we are cautiously, obviously, optimistic around that vote.

The balance of our regulatory approval processes are progressing as expected.

And at this point, we believe we remain on track to close the merger during the second quarter of this year.

Those of you who've been tracking the various dockets have likely observed that the latest developments in the FERC and PUCT approval processes.

FERC did request some additional analysis related to Dynegy's [MISO] assets, and we provided the requested information on February 5. We have requested FERC approval of the merger by March 15.

And at this point, we have no reason to believe the FERC approval process would extend beyond the second quarter of 2018.

In fact, there are similarities between our application and the recently approved ECP-Calpine transaction, which took approximately 5 months to receive FERC approval.

While we cannot predict with certainty, a 5-month approval process would place our merger approval at FERC in the mid-April timeframe.

Similarly, in the PUC of Texas approval process, the PUCT's staff has filed its recommendation regarding the commission's approval of the merger, and Vistra has filed its response, all in accordance with the administrative law judge previously filed administrative schedule.

Importantly, no party has requested a hearing, meaning that the commission will likely be able to act on the merger approval at one of the upcoming open meetings in late March or mid-April.

It is important to remember that in this instance, the PUCT's approval is based solely on whether the combined company is at or above the 20% market share at the time that the merger closes.

We do have a robust sales process.

And as most of you know, it's in place for the potential sale of 3 gas steam units: Trinidad, Graham and Stryker.

Should the commission ultimately side with staff on the issues of grandfathering of Lake Hubbard or our proposed DC-Tie stipulation, we are fully prepared to divest of these assets in order to fall below the 20% cap, which is a commitment we made in our merger application.

We forecast the divestiture of these assets would have an immaterial impact on EBITDA in 2018.

At this time, we remain confident we will be able to close the merger with Dynegy in the second quarter of 2018, as I had mentioned.

As previous -- and as we previously forecasted, my view is it's most likely in the mid-April to mid-May timeframe.

On the financial side, we remain optimistic about the combined earnings power of the pro forma entity.

And we continue to believe there could be upside to both our previously announced EBITDA synergy targets as well as to our operational performance improvement targets.

We have a robust integration process underway.

That process put us in a position where we would be in a position to integrate, close the deal and take over as of March 1. So we're well on our way.

Even though we think the approval obviously will be beyond that, we wanted to be ready as soon as possible.

And you guys all remember that through that process, we believe we had $225 million of projected EBITDA synergies that we announced in October.

We believe that there's upside to that, and that upside we have already targeted and identified.

Similarly, our OPI process is well underway.

And at this stage in the process, we continue to believe we'll be able to exceed the $125 million of projected EBITDA enhancements we previously announced.

As I indicated earlier, I expect we will be able to provide the market with our updated synergy and OPI targets shortly after we close the merger.

When we provide an update on the merger synergies and OPI targets, we want you to know that we believe you can -- that we believe that you can take them to the bank.

We want to put the time in, the effort and to nail those down so that you could be comfortable that we can execute against them.

I continue to believe this merger will bring significant value to shareholders of both companies through the value levers we have identified.

Moreover, the geographic fuel and earnings diversification of the combined enterprise should improve stability of earnings and cash flow going forward as -- and also derisk the enterprise as well especially from a natural gas exposure standpoint, as I discussed previously.

We are prepared to quickly and efficiently integrate our operations following the merger closing.

And as always, we'll keep you informed of relevant updates along the way.

Before I turn the call over to Jim Burke, I would like to touch briefly on capital allocation, as I know this is a topic of much interest to the financial community given our expected significant EBITDA conversion to free cash flow.

First and foremost, as we noted when we announced the merger transaction in late October, our priorities following the closing of the merger will be to seamlessly integrate our operations, achieve and exceed our synergy and OPI targets and execute the combined business operations.

We do believe these efforts will result in significant cash flow generation for the combined company.

For the first 12 to 24 months following close, our focus will be on paying down our debt to achieve our net debt-to-EBITDA target in the range of 2.5x, as we've discussed before.

We'll, of course, evaluate growth opportunities during this period, predominantly on the retail side, and we'll be flexible on allocating capital to these tuck-in opportunities as we do not control when accretive transactions might present themselves.

Longer term, we are going to have to turn our focus to some sort of return of capital.

We will always plan to maintain some capacity to buy back our shares, particularly when we believe our shares are significantly undervalued, like we believe they are today.

We would also entertain paying a recurring dividend as we believe a more systematic dividend would be more attractive to investors, and therefore, accretive to our stock price, as opposed to paying uncertain special dividends, which are hard for investors to predict and therefore difficult to value.

We, of course, have not made any decisions related to future capital allocation as we are firmly focused on closing the Dynegy deal and wringing out the value that we have promised to the market.

We'll be working with our board in the months following the merger to evaluate capital allocation alternatives.

I can say, however, that if we did make a decision to pay a recurring dividend, it would need to be meaningful -- likely in the 3% to 4% dividend yield range -- and we would need to have confidence we could grow the dividend over time.

This would be the only way to ensure the market would give us credit for a recurring dividend if one were implemented.

If we execute and achieve the expected free cash flow projections, we should be able to comfortably handle a recurring dividend with the attributes I just described.

I will now turn the call over to Jim Burke to cover 2017's operational highlights.

Jim?

Thank you, Curt.

Let's now turn to Slide 9 to briefly discuss the 2017 commercial highlights.

Consistent with our fossil fleet's performance in the first 3 quarters of the year, Luminant once again delivered high levels of commercial availability in the fourth quarter, finishing the year at 96%.

As we've noted in the past, it is critical for operations teams to ensure units are available when market prices are most attractive.

This will be even more important in 2018 given the tighter reserve margins expected in ERCOT, increasing the probability of scarcity events.

In addition, strong commercial availability supports Vistra's ability to opportunistically hedge our assets, which, as you know, is critical to our ability to deliver a more stable and higher earnings profile in volatile power price environments.

For the full year of 2017, Luminant's commercial operations team realized prices that were nearly 44% higher than settled prices.

It is this active asset management approach we take toward hedging and dispatching our generation fleet that has allowed Vistra to realize prices that are materially higher than settled prices in periods of sustained low wholesale market prices.

You'll see, however, that Vistra is forecasting a much smaller hedge premium in 2018, which is exactly what you would expect in an upmarket.

Vistra opportunistically hedges its assets in order to mitigate risk from dramatic changes in power prices, particularly to the downside.

For the past several years, as power prices have been falling, Vistra has been able to realize prices materially above settled prices as a result of its opportunistic hedging approach.

We are always willing to take the risk of higher settled prices as Vistra is generally net long and can capitalize on scarcity pricing events, should they occur.

In fact, as power prices rise, our net length actually increases.

And with that incremental length, we're able to capture upside from the positive movement in power prices.

Even if our hedge positions are negative in those circumstances, the entire fleet is better off by the upward movement in power prices.

Importantly, by hedging into the volatility we observe, we are minimizing the risk of a downmarket.

In fact, Vistra plans to take advantage of the recent upward momentum in the forward curves to opportunistically hedge in the out-years in order to minimize the risk that prices could decline in the future in the face of a rational newbuild, for example.

So as long as we continue to see reasonable levels of volatility in the forward curves, we'll continue to opportunistically hedge our wholesale length in future periods, which should continue to create more stability in our earnings profile.

Before I leave this slide, I'd like to recognize and express our appreciation for the hard work of our generation teams at the 3 retired coal sites.

The dedication of these teams resulted in safe and highly reliable operations for many decades in a very competitive market.

This is a truly remarkable achievement, and we are grateful for their efforts.

Turning to Slide 10.

The consistent performance of our retail operations also contributes to the relative stability of our earnings.

You can see that our residential net attrition rate continues to decline, falling to 0.4% in '17 down from 0.7% in '15 and '16.

The stabilization of our residential customer accounts reflects both the maturity of the ERCOT market as well as our retail team's diligent focus on delivering innovative products and a superior customer experience.

Maintaining solid counts in 2017 in addition to strong margin and cost management proved to be an important driver for our retail segment to overcome the negative impact of mild weather in 2017.

As the chart on the bottom left quadrant of Slide 10 shows, our energy degree days in North Texas in 2017 came in below the 10-year average in most months, but the mild weather was particularly pronounced in the first quarter of the year.

While it might be counterintuitive, in normal weather years, the retail business earns the majority of its EBITDA in the first, second and fourth quarters of the year.

This is because the cost of power for retail electric providers in ERCOT is materially higher in the summer months, as we depict in the graph in the bottom-right quadrant of the slide.

This is another benefit of Vistra's integrated operations as we have a wholesale business that is dependent on the summer months, paired with a retail business that makes more money in the remaining periods.

Given this phenomenon, the fact that energy degree days were so far off of the 10-year average in the first quarter of '17 and even outside of the 10-year average band in the month of February, created a bit of a challenge for the retail business to overcome in 2017.

Through disciplined cost management, strong margin management and impressive customer acquisition and retention efforts, our retail team finished the year right in the middle of its 2017 guidance range.

I'd like to anticipate a potential question given that wholesale prices are rapidly rising in ERCOT.

Some have commented to us a concern that our retail market share and EBITDA may be under pressure in this type of rising power price environment.

However, our retail business has been resilient through both high and low as well as volatile wholesale price environments, as evidenced by an exceptional EBITDA year for our retail business in 2011, which was a highly volatile year, and the business earned more than $850 million.

We were able to achieve these results due to our customer mix, our hedging practices and our product suite relative to other retail electric providers.

I'm proud of our team's execution in 2017 as we continue to be a leading retail electric provider in the state of Texas.

We are excited to expand our unique retail capabilities into the Northeast market following the closing of the merger with Dynegy.

In fact, our retail teams are already evaluating various growth strategies to further enhance our integrated presence in those markets after the merger closes.

We are excited about our growth opportunities in 2018 and beyond.

I will now turn the conversation over to Sara Graziano to discuss ERCOT market fundamentals.

Thank you, Jim.

Turning now to Slide 12, we wanted to spend a few minutes discussing the latest ERCOT CDR report as well as our view of the potential for a new resource development in ERCOT.

As many of you know, ERCOT issued its latest CDR report in December of last year, reflecting material changes from its prior version published in May of 2017.

Of note, ERCOT's 2018 summer reserve margin is now projected to be 9.3%, down from 18.9% in its prior forecast.

The primary difference between the December and May estimate is the inclusion of more than 5,000 megawatts of recently announced retirements, which include Vistra's 3 coal plants retirements totaling approximately 4,200 megawatts.

It is our view that these recent retirements indicate that market forces are working as designed in ERCOT as uneconomic assets have now exited the market, following a period of sustained low wholesale power prices.

With the now tighter supply-demand dynamics in ERCOT, forward prices have improved, and the probability for future scarcity events have increased.

Despite the recent uptick in forward curves, it remains our view that new thermal resources are uneconomic to develop in ERCOT, and we continue to believe developers will struggle to attract debt and equity capital.

It can be very difficult to finance new development in ERCOT's energy-only market, which lacks any type of capacity payments to support the debt service.

This is particularly true of peaking assets that rely heavily on scarcity events to capture a revenue stream.

On the equity side, we calculate unlevered returns for both CCGTs and gas-peaking assets to be in the 5% to 7% range in the current pricing environment.

As a result, while it might be easy for developers to obtain necessary permits and secure EPC contracts for newbuild projects, we continue to believe new thermal development is irrational from an economic standpoint and could only hope financial market players will bring discipline to their investment decisions going forward.

The fact of the matter is, we have a flawed development model in place where developers can earn huge fees to site, permit and construct new thermal resources.

Those developers find third parties to ultimately finance the asset, and then they exit the project before the asset is ever turned on.

It is the third-party investors that end up losing money, while the developers earn 100% of their fees on the front end.

It is a terrible model and can only be cured if financial players stop throwing good money after bad investments.

As Curt has mentioned time and time again, since the restructuring of power markets began in the late 1990s, we are hard-pressed to find more than one merchant power plant investment where the original equity owner received an adequate return and many suffered financial distress.

Recently, a couple of relatively new projects in ERCOT have also experienced financial distress.

Hopefully, this reality will start to sink in with the financial community, so debt and equity investors stop making irrational investments.

Assuming we do see this discipline by the financial community, we anticipate the pace of new thermal development in ERCOT will lag the current CDR projections given their current economics.

Rather, we expect the next marginal new resource to be developed in ERCOT will be solar or wind.

That being said, geographic and transmission constraints in ERCOT will continue to limit the ability for developers to site new renewable resources.

For example, let's go ahead and turn to Slide 13, which includes an irradiance map of the state of Texas.

Irradiance is a major driver of returns on solar developments, and small changes in irradiance can have a material impact on the returns of a project.

As you can see on this map, irradiance is its strongest in West Texas, which is where returns for solar developers would be the most attractive.

However, despite this attractive irradiance in the West, new development will be limited by the availability of unencumbered land with access to uncongested transmissions, which is challenging to identify in West Texas.

Similarly, solar development returns remain very sensitive to tax appetite.

Without the ability to fully utilize the investment tax credit, returns decline to single digits.

We expect tax reform will negatively impact the appetite for tax equity investments in new solar development, which should dampen the pace of new construction.

New wind developments, which we project to be slightly less economic than new solar developments, will face similar siting and transmission constraints in ERCOT.

As a result, while we do forecast that incremental solar and wind resources will be developed in ERCOT, we do not expect any such developments to overwhelm the market in the near term.

I will now turn the call over to Bill to discuss our 2017 financial performance in more detail.

Thanks, Sara.

I'll start with the financial results on Slide 15.

As Curt highlighted at the beginning of the call, adjusted EBITDA for the consolidated business was $1.455 billion for the full year, and adjusted free cash flow in 2017 was $831 million.

Full year adjusted EBITDA was in the top quartile of Vistra's narrowed guidance range of $1.375 billion to $1.475 billion, and adjusted free cash flow was right in the middle of Vistra's narrowed guidance range of $770 million to $900 million.

For the full year, the retail segment's adjusted EBITDA was $779 million, in the middle of the guidance range of $760 million to $810 million.

This result reflects solid performance by our operations teams, following a difficult start to the year as a result of the unprecedented mild weather in the first quarter.

In fact, February 2017 was the warmest February on record in North Texas with an average temperature of 60 degrees and 9 days at or above 80 degrees.

Through disciplined margin and cost management and superior customer acquisition and retention efforts, our retail team largely overcame the negative impact of this mild weather, delivering solid financial results for the full year.

Now turning to our wholesale segment.

Full year adjusted EBITDA was $696 million, above Vistra's guided range of $630 million to $680 million.

Strong commercial performance and expense discipline throughout the year drove these results, which were partially offset by Comanche Peak Unit 2's unplanned summer outage.

As Curt mentioned, all of our operating teams displayed a true dedication to achieving maximum results for the business in 2017, and their disciplined execution enabled Vistra to achieve financial results at the top end of our guidance range despite some fairly significant headwinds.

We are now taking the same disciplined approach as we work towards exceeding our synergies and OPI targets and preparing for a seamless integration with Dynegy following the closing of the merger.

Turning to Slide 16.

You can see that we are not changing our standalone 2018 adjusted EBITDA and adjusted free cash flow guidance ranges at this time.

As Curt noted, starting in 2018, we are also introducing a new segment called the Asset Closure segment which will track and report all of the expenses and cash flows related to decommissioning and reclaiming our Monticello, Sandow and Big Brown plants and their related mines.

We will report this segment separately in both our financial reporting and earnings materials until we no longer have any expenditures associated with the retired assets.

We are introducing the Asset Closure segment to more closely align financial reporting with how both our management and board will be evaluating Vistra's business operations going forward.

In addition, we believe providing visibility into the expected adjusted EBITDA and adjusted free cash flow contributions from Vistra's ongoing operations will be helpful to investors as they value our business.

Given that the asset closure segment relates solely to the winding down of retired operations, we believe it is more appropriate to apply EBITDA multiples and free cash flow yields to the earnings expectations of Vistra's ongoing operations.

In 2018, we are forecasting adjusted EBITDA from the asset closure segment will be negative $50 million to negative $40 million and that adjusted free cash flow from the asset closure segment will be negative $90 million to negative $70 million.

The expenses that we'll report -- will be reported in the asset closure segment include adjustments to the asset reclamation obligation liability related to the sites, plant property taxes, railcar-related expenses, labor and third-party expenses that are ineligible to be included in the liability for the asset retirement obligations such as on-site security and allocated costs, other facility-related expenses and miscellaneous regulatory fees payable by the retired sites.

The expenses and any related revenue opportunities associated with the decommissioning and reclamation of these plants and mines will be managed by a Vistra operations team tasked solely to minimize expenses and maximize any revenue opportunities associated with this segment.

Excluding these expenses in cash obligations, Vistra is forecasting adjusted EBITDA from its ongoing operations will be $1.35 billion to $1.49 billion and that adjusted free cash flow from the ongoing operations will be $690 million to $820 million.

If you also exclude the 2018 nonrecurring capital expenditures relating to the generator capital at Comanche Peak, our adjusted free cash flow guidance range from the ongoing operations would be even higher at $760 million to $890 million.

We hope you find this additional detail helpful as you analyze the performance of our operations going forward.

Turning now to Slide 17.

We have updated our hedge profile and related sensitivity as of December 29, 2017.

We have also included in our 2019 hedge profile information.

As you can see, as of December 29, we were materially hedged for 2018, which will somewhat limit our ability to capitalize on the recent uptick in forward price curves in this year.

However, we do see meaningful opportunity to capture upside in 2019 as we were approximately 22% hedged on a natural gas equivalent basis and approximately 42% hedged on a heat rate basis for the year as of December 29, 2017.

We will continue to opportunistically hedge into 2019 and beyond to the extent forward price curves are at or above our fundamental view.

Last, turning to Slide 18.

Our capital structure has been modified slightly since September 30, 2017.

In December of last year, in connection with the repricing amendment, Vistra reduced its term loan C facility from $650 million to $500 million.

Also, as a result of this December 2017 repricing amendment, together with the repricing transaction in February and August of 2017 and February of this year, Vistra has now reduced its annualized interest expense by approximately $66 million.

We will continue to be opportunistic to take advantage of occasions to reduce our borrowing costs from time to time as the market permits.

As for our 2017 leverage metrics, we concluded 2017 with net debt-to-EBITDA of 1.7x, and that metric is forecasted to continue to decline in 2018 on a standalone basis.

We expect Vistra's leverage profile to remain strong following the closing of the Dynegy merger, with net debt-to-EBITDA forecasted to be just over 3x at year-end 2018.

Maintaining a strong balance sheet and bringing our net debt-to-EBITDA to approximately 2.5x or lower as quickly as possible following the merger will be a capital allocation priority for Vistra.

We believe a strong balance sheet is critical to our success as we transition from being an ERCOT-only player to the leading integrated power company in the U.S.

With that, operator, we're now ready to open the lines for questions.

(Operator Instructions) Your first question comes from Greg Gordon with Evercore ISI.

Just to go back and level set, when I look at the Vistra-Dynegy pro forma that you gave when you announced the deal, you were looking at a 2018 annualized range of $2.875 billion to $3.125 billion.

Is that right?

I'm looking at Page 16 of that investor presentation.

Yes, that's right.

That's correct.

And you're saying that you're not updating guidance at this point, but you think that the OPI is going to likely be better, overall level of synergies is likely to be better.

And independent of all of that, just increases in the forward outlook in both PJM and ERCOT would reset that pro forma as well.

So sort of 3 different drivers we have to contemplate when we think about the update you'll give us when you close the deal.

That's right.

That's exactly right.

Those are the 3 levers.

Fantastic.

The -- I do have a question on a totally separate tangent.

I appreciate actually the conversation that you guys are engaging in on renewable resource development in Texas.

I'm increasingly getting questions on battery storage as it pertains to being bid in colocation with wind and solar in different regions and at what point that might become a threat to volatility via the ability to sort of shift peak.

Do you have an ability to talk about that at all on this call?

If not, we can follow-up, but I think that's something people are increasingly worried about, although it doesn't seem like the market structure in Texas would support the viability of that in the near future from my perspective.

Yes.

So Greg, I will tell you that we are -- we have immersed ourselves into the battery world.

And just to give you a little bit of insight, there could be some opportunities for us even around some of the sites that Dynegy has in California.

That's probably the best place to experiment with batteries, given the support they have.

It is tougher in ERCOT.

But what I will tell you is we're looking at it in ERCOT too, around Upton 2. What we found is that you got to get in this and you got to understand it, and you got to be an investor to really get under the hood.

But I think I've said this before, we believe that batteries are real, and that they are going to play a role in our business.

And you got 2 options when you're a traditional generator.

You can stick your head in the sand or you can participate.

We view it as an opportunity.

The solar investment for us at Upton 2 was a way for us to get into that business, and we did it in an economic way.

There could potentially be something around batteries where we could offer a product to our retail customers that is battery-related, which I think there are some people who are -- tend to be green-oriented that might like a product that's a solar-battery combination, and we're working through that.

But what I'll just say is that we are aware that batteries are going to play a role, and we are trying to participate, and we're just looking for the best places to do it.

Because as you guys know, you can't really participate in these new fledgling technologies and lose a bunch of money.

Investors are just not going to put up with that.

So we have to find a way to participate in a way that we can make money.

And the one nice thing about us is that our integrated business does allow us to do that.

And you should expect to hear more from us around that in the future.

Okay.

But you don't see the economics of batteries as being in a position in the near term or medium term in Texas where they could become a meaningful load shift at a return that would be viable for a large new entrant?

We do not.

We do not see that even with the enhanced forward curves.

One thing about the forwards that people probably -- we didn't really articulate but is important is, forwards are really kind of popped up in '18, '19, a little bit into '20, but then they come off.

And I guess, the market is expecting something to happen, like new build.

It would be tough.

By the time you would do something, put it in place, I mean, I just don't think that the forwards, where they are right now, and the backwardation in those curves would support a battery investment.

It's really tough to make it happen.

If it's just purely a merchant battery investment that would be difficult.

But I think that we may be able to do that, supported by a retail offering that had significant margin to it.

We don't know yet whether that's something that our customers are interested in, but we're working through that.

Your next question comes from Shar Pourreza with Guggenheim Partners.

So just on a consolidated entity, appreciate waiting for deal closure, but maybe we could chat directionally.

As you think about sort of north of $1.5 billion in free cash flows post-merger with upside from additional synergies, the curves, price formation, maybe another 1 to 2 more coal retirements outside of ERCOT for Dynegy, I mean, you sort of -- Curt, you sort of talked about the dividend and buybacks in your prepared remarks.

But how are your thoughts sort of evolving around the ultimate balance sheet leverage targets you currently guide?

So sort of the way I'm thinking about is, for a company that has so much excess cash post a dividend and buybacks, is 2.5 to 3x net of gross debt really appropriate?

Or you're thinking something tighter over the long term similar to other cyclical energies industries?

Yes.

So that's -- I mean, that is a very good question.

I think we have a target to get to that 2.5 net.

And I think when we get there though, I think -- and we're at a stage where we pay down debt and we have excess cash, I think we are -- and that the investment community as well as the rating agencies have gotten more comfortable with our integrated business and the resilience of it and the stability of the earnings, I think we may want to turn our attention to a discussion about whether we can get an investment-grade integrated power company again.

And to do that, we think we would have to carry less leverage than the 2.5x net, but that could be advantageous to our company to take that next step.

And so I think for us, we want to sort of walk before we run here.

We want to get -- prove to the market we can get these synergies and the OPI savings, generate the cash flow, pay down the debt, look for some tuck-in asset-type things around our retail business.

And if we could do that and hit the numbers and be consistent, I think we are going to want to turn our attention to what's the next phase for the company in terms of leverage and in terms of return of capital to shareholders.

Clearly, that is a board discussion and will happen in 2019.

I mean, what are we talking about?

We just had a board meeting last week, and we had this conversation.

But I think you point to a very interesting concept as to is the 2.5 where you're in, or do you go somewhere from there?

I think that is really dependent on whether there's value to going to that next level of reducing debt, and that puts us in a better position to execute our strategy at that point in time.

So it clearly will be on the table as a discussion point.

That's helpful.

That's good.

And then just, Curt, just on a standalone EBITDA guidance range on -- just for Vistra.

Obviously, we've seen the move in sparks.

I mean, you clearly highlighted it in your slide decks.

As you sort of think about Vistra and if you back out the asset closure segments and sort of the nonrecurring items, are you -- if you were to mark, are you sort of guiding to the top end of that 2018 range?

Are you -- or are you sort of thinking it's a brand-new higher range?

I think what we would say is that there's that opportunity to move in that direction.

You'll remember, we're very heavily hedged in 2018, and we did that from a risk management standpoint, not knowing if we were going to shut down the units, whether we could get there or not.

And obviously, it's history now.

We have done some things to reposition our portfolio that we think will be good for us in '18.

I will tell you that the bigger upside for us is in '19.

And we believe that as we roll through 2019 -- or excuse me, 2018, especially when we see this summer, the 2019 curves are going to move up.

That's why you haven't seen us take a bunch of this off the table for '19 because we believe it will move up in the range of where '18 is right now.

So I think that's the bigger play, but there's still some room to move, and I think you're -- directionally, you're probably not too far off from what we see the kind of curve juice left in it for 2018.

Okay.

Great.

So the summer of 2018 is likely the inflection point for your forward hedges.

Excellent.

Your next question comes from Julien Dumoulin-Smith with Bank of America.

I wanted to just focus on tax reform a little bit here.

Obviously, you've got projected pretty minimal cash taxes in '18.

But how are you thinking about that over the sort of longer term here, what a normalized view would be?

And how you do you think about optimizing Dynegy's NOL position into 2019 and onwards?

Is there any way to think about tax reform and a tax -- cash tax rate, either in a percentage term or in nominal terms?

How are you thinking about it and the exposure and mitigating strategies?

Yes, Julian, this is Bill.

I think our current view is still based on what we showed in the 8-K that we issued in January, where you'll see we're a nominal taxpayer, very small amount in '19.

We do pay cash taxes on the margin -- sorry, in '18, but we do pay cash taxes on the margin from 2019 and beyond.

The one thing I would add, I think Dynegy mentioned in their earnings release that they have AMT credit refunds coming.

Vistra will succeed to those AMT credits and the related refunds or at least any that haven't already been received by or filed by Dynegy prior to the merger close.

We're still calculating the amount and timing of the benefit to the combined company, but I think certainly, we see that those AMT credits will be an incremental benefit to the cash tax schedule that we showed in the 8-K.

Got it.

And that shouldn't be too material?

I think the numbers in the Dynegy 8-K actually were pretty significant, and I think we think there's going to be real benefit to the combined company as well.

Got it.

Okay.

Excellent.

And then -- and just to clarify there, your other comment on dividend.

You'd alluded to 3% to 4% yield.

How do you think about like a payout ratio, if you will, against the core business and growth of the company?

I mean, is this predicated on growth of the retail company or growth of the overall company?

And would you be paying conceptually a dividend against one side of the business or other, or overall?

Well, I think dividend will be -- and we would think about it overall.

I do think the one thing we've looked at though, and you know this, but the conversion from EBITDA to cash flow off our retail business is substantial, right?

Almost, it's in the 90%.

If you think about, just in the worst place that you could be where your wholesale operations cover your costs essentially other than the retail business and you just had the retail business generating cash, that's in the $700 million or $750 million range and then a 3% or 4% yielding dividend, we'd easily will be able to cover that.

So -- and that just from a pure risk management standpoint, we feel pretty comfortable just given the conversion.

And the total conversion for the company is in the 50% to 60% range that we predict.

And that's obviously been improved, that conversion, given the tax situation that we expect to have when we do -- when we close the Dynegy deal.

So I think at the end of the day, we feel pretty comfortable with that kind of range.

In terms of the trade-off, I think it sounds simple but it's not.

I mean, at the end of the day, we don't control the opportunities that come our way to grow our business, so we have to be somewhat opportunistic, and I think we'll be that way.

But I think we're going to be a lot stingier about investments in the generation side of our business outside of maybe renewables that support -- and batteries and other things that support our retail business.

And I think our bigger focus is going to be more around our retail business.

You know this, but we are significantly long in PJM and ISO New England markets, and we'd like to be shorter than that.

So we are embarking on developing a strategy this year in 2018.

We're already in the middle of it on our retail business that's outside of Texas.

And it's focused on a double-pronged, not rocket science, we're going to try to grow organically.

And then to we will look for opportunities for acquisitions that we think are -- have a compelling value proposition.

We bring a lot to the table on that, one, an expertise in retail.

But secondly, we can wipe out a lot of costs that a company would bring just, given just the scale of our business.

So that would be the more -- the focus on the growth side of it.

The dividend, I think, would end up being sort of -- I think we can do both.

So you can -- you almost can say that we're a value play, to some extent, but we'll have growth opportunities and we think we can pay a dividend with both.

This is after we pay down the debt.

In terms of how do we look at whether we put money into a growth alternative or something else, including a buyback, or whether we do a special dividend down the road, I think that's just purely economics and where we think the better opportunity is.

And if we think our stock is so depressed that we think that's a better investment than putting money into some growth initiative, we'll do that.

And I think that will be a signal to the market, that that's how we've analyzed it.

I'm not sure if I got directly to what you were asking about, but that's how we think about it.

Your next question comes from Steve Fleishman with Wolfe Research.

Just on the asset closure segment, is there any way to get a sense of the -- how long this might last and the ultimate size?

Just if we want to pull out the EBITDA going forward, it'd be good to know kind of what -- a range of the total cost would be.

Yes.

So we are going to provide that, Steve, when we -- for the Q1 call.

We do -- we are working on that.

And what -- there's a couple of things we want to do.

We just want to draw the attention to the costs associated with that segment so that you know exactly what it is.

And we're also going to give you a runoff of that.

So that's coming, but we are -- we definitely understand in order to really -- to do this right, we have to provide you with those cash expenditures so that you guys can value it as cash, right?

I mean, that's the only way to do it.

We are discussing whether we want to provide a separate ARO for that segment relative to the rest of the company.

Because right now, you could argue that our ARO is somewhat of an estimate for that, but we've been discussing whether we want to separate those because we're going to have an ARO for Oak Grove and when we close with Dynegy for those plants.

But I think what we probably need to do is show you that.

And that's probably as good of an NPV look at the cost of those expenditures that we have.

In fact, it's a pretty darn good -- the way we do it, it's a pretty good estimate.

Okay.

So maybe the AROs...

Yes, go ahead, Steve.

The AROs that you have on the books at year-end might be at least a starting point for that?

Yes.

Just remember it's got our gas plants in Oak Grove and Martin Lake in it, but yes, that's a reasonable starting point on that.

And then we'll have to provide you with a specific information.

And we plan to do that.

Okay, great.

And then just -- I want to just make sure, because it's great you've talked about upsides to the merger guidance on cost and synergies and forwards.

Just around that out though, is there anything that has gone against you since you gave that guidance?

Or is everything else kind of okay and these are all just pure upsides?

Yes.

I would say the one thing that -- I don't know that it went against us because it was within our range, but it was in the lower end of our range.

The ISO New England capacity clear was disappointing.

And I think it's interesting, Steve, that I think it kind of indicates a flawed market, right?

On one hand, ISO New England saber rattling about we're going to run out of generation.

On the other hand, the market clears at 4.63.

That -- those seem to be inconsistent.

The good news is I think they understand that, and they're trying to fix it to some extent, which I think is actually a reasonable step forward with the dual clear that they're -- I think people are calling it [Casper].

I think that has a chance of providing an exit for plants that really want to get out, and it's really hard to do that right now in that market.

So -- but that was a disappointing.

I -- we were hopeful that it would be more in the range of where it had come out the previous year at the 5.30 range.

It came in at 4.63.

The effect of that, though, is relatively immaterial.

And clearly, we think the upside is greater than the negative on that.

But I have to be honest with you.

We would have liked to have seen a better clear, and we're hopeful that these capacity market reforms will move things in a better direction.

Okay.

And then just last clarification, the tax gains at Dynegy that you mentioned that they disclosed, those are all incremental to the tax disclosure that you put out at the beginning of the year for tax reform.

So if you put that out again, your tax payments would be further reduced.

That's correct.

That's -- yes, that's right.

Your next question comes from Abe Azar with Deutsche Bank.

Following up on the ERCOT fundamental discussion.

At what price level do you think new build gas projects can get financed in Texas?

And relatedly, given the constraints on land and transmission, where do you see peak renewable penetration?

So on the combined -- I think you're thinking of combined simple cycles.

Sara, do we -- do we have something that -- I mean I have a guess on that, but I just -- I hate throwing out guesses.

Yes.

It's not necessarily straightforward to translate it into a power price change because it depends on really what happens in the summer since it's less at summer peak's pricing.

But I -- do we not have -- I thought we had at onetime -- Steve, we'd done -- Steve Muscato runs our trading floor -- look, I'll tell you what, Abe, let's -- because I think we've done this work before, and we can give you kind of what we think an on-peak 5 by 16 in the summer would have to be to kind of support the economics of a combined cycle plant.

So give us an opportunity here to do that.

And then maybe we can provide it.

I just don't have it at my fingertips right now.

That makes sense.

And on the renewable front, do you have some sort of penetration rate where you think the system doesn't expand beyond that just because of land and transmission constraints?

Well, we have roughly -- I think we showed this roughly 2,000 megawatts that -- of solar penetration.

And what do we have there?

About 50 -- almost 6,000 megawatts of wind coming in?

And I think we would argue that that's stressing the system at that level.

But we do believe that, that will come in, so you can add those things together.

But it's probably in the 8,000 megawatts of wind and solar that will put you up against congestion.

I would also say, and I think we've talked about this, I don't see a big appetite here in Texas after spending roughly $6 billion on CREZ to really actually help additional renewables get to the market.

In fact -- and many of the politicians here are now questioning the wisdom of what they've done because obviously, we shut down 4,200 megawatts of coal.

And associated with that, I think with the mines and the coal plants, we were upwards of almost 1,000 people that were let go.

Those are voters, and they had to think about that a little bit.

And then when you do, obviously, renewables, the amount of people you need to run those is very small.

So I don't see an appetite, Abe, to really expand that, but I think we believe that you could put in 8,000, 9,000 megawatts of wind and solar.

And probably the system may get stressed at times, but you could probably find a way to make that work with the current system, maybe with a few smaller investments to make it work.

Go ahead Steve.

Yes, I was going to say the best economics are actually in the Panhandle, but that should become saturated from a transmission perspective, probably around the end of 2019.

So that will have to shift investment predominantly to West Texas that has lower overall capture rates (inaudible) .

Your next question comes from Michael Lapides with Goldman Sachs.

Easy question.

As you look at the combined portfolios, are there any regions of the country where you would like to have a bigger or a different type of presence?

And are there any regions of the country where you may have a presence but you kind of look at that region as a bit noncore or the portfolio you have in that region is noncore?

That's a good question.

So look, I think the way that we think about it is that the regions that we feel the most comfortable with and really where the bulk of the value was with PJM and ISO New England.

I'm not sure that one asset in New York is strategy, and so we'll have to make a decision.

It's a good asset and not saying anything against the asset.

Also, not sure about the long-term market in New York.

I've been in that market for many years, and we'll have to take a hard look at that.

MISO, I think is -- that's got multi-levels of work to do.

We've got a good retail business there, but we have some challenges around -- of that asset base there, both in terms of performance, but also just economics.

And I know that Dynegy and Bob were working on that.

I mean, they're working on the multi-pollutant standard to basically create flexibility to make decisions about what assets were in, what asset were out.

They also were trying to do capacity market reform, which I think has been tough sledding to get done.

MISO tried to take something and pushed it back on them, although it seems like there may be another kick at that cat.

But at the end of the day, I think that's going to be tough to get -- just in that zone, it's going to be tough just to get a reform there.

And so at some point, when you don't get the reform and you are successful at doing what you need to do around the multi-pollutant standard and freeing up the assets, we've got a portfolio optimization exercise to do no different than what we did in Texas.

And I think that may result in maybe a shrinking our size of our generation.

Whether that means we try to sell assets or what, I don't know yet.

And then I think Bob would tell you this because he tried to sell the assets in California.

It's not clear to us that that's a strategy either with those assets there.

Actually, they've had decent financial performance as of late, but that's a tough market to bet on in the long run.

But we do like -- there's a couple of the sites there for potentially, as I said earlier, maybe batteries or something else.

We'll have to decide whether we do it or whether we sell it and develop it and sell it to somebody.

We just don't know yet.

But I think the core markets are PJM, ISO New England.

And of course, the way I think about it is we shut down 4,200 megawatts in Texas of challenged assets.

We may have to sell 1,200, 1,400 megawatts of older -- very old steam units in Texas.

But we're getting about 4,000 megawatts of combined cycle plants, mainly combined cycle plants in Texas.

And we're getting (inaudible) Creek, which is in the South zone, which sees better pricing.

I like that trade basically, that swap of what we had to what we would get.

And we think that, that creates for a stronger fleet in Texas.

So remember, when we started all this, when we came out of bankruptcy, we thought we'd like to get somewhere 2,000 to 4,000 megawatts of combined cycle plants.

That was with the anticipation we may have to get out of the market, and we did that.

We just did it a little bit in a circuitous route.

We did it through Odessa, which is an advantaged, obviously, gas price plant.

And then we also did it through the Dynegy transaction, where we're picking up roughly 3,000 megawatts of very good combined cycle plants.

So those are really the key ones.

I hope that answers your question.

This concludes the Q&A session for the conference.

I'd now like to turn it back to Mr. Curt Morgan for closing remarks.

Well, once again, we appreciate everybody on the call.

Sorry, it went a little bit long here.

We had a lot to talk about, obviously, and we look forward to continuing our dialogue about our company.

A lot of good stuff is going to happen in 2018 that we're going to need to stay close with you all and communicate as we go through it.

We're incredibly excited about it.

We can't wait to get the deal closed and be able to come out and talk to you about the upside around this thing.

We just -- everywhere we turn, we feel like we've got some really strong winds at our back, and we want to communicate it.

And we'll do so once we close the transaction.

So thank you.

This concludes today's conference call.

You may now disconnect.