Vistra Corp (VST) 2019 Q1 法說會逐字稿

Good day.

My name is Jack, and I will be your conference operator today.

At this time, I would like to welcome everyone to the Vistra Energy First Quarter 2019 Results Conference Call.

(Operator Instructions) Thank you.

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

Thank you, and good morning, everyone.

Welcome to Vistra Energy's investor webcast covering first quarter 2019 results, which is being broadcast live from the Investor Relations section of our website at www.vistraenergy.com.

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

Joining me for today's call are Curt Morgan, President and Chief Executive Officer; and Bill Holden, Executive Vice President and Chief Financial Officer.

We 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 2 and 3 in the investor presentation on our website that explain the risks of forward-looking statements, the limitations of certain industry and market data included in the presentation 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 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 kick off our discussion.

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

As always, we appreciate your interest in Vistra Energy.

As you can see on Slide 6, Vistra finished the first quarter of 2019 reporting adjusted EBITDA from its ongoing operations of $815 million.

Results are above consensus and in line with management's expectations for the quarter.

Notably, when compared to first quarter 2018 pro forma results for the merged Vistra and Dynegy entities, we finished the quarter nearly $240 million ahead of last year, primarily as a result of favorable realized wholesale prices in 2019, higher retail margins and the realization of merger synergy and OP cost savings consistent with the estimated $565 million of annual EBITDA value levers we have announced.

We also remain on track to capture the $310 million of additional after-tax free cash flow value levers from the merger, which are bolstering our free cash flow generation and conversion percentage from EBITDA.

On a smaller scale but equally important in advancing Vistra's operational and earnings diversity, we continue to expect we will be able to close the Crius Energy acquisition in the second quarter.

At this point, the Department of Justice review has expired and the Crius unitholders overwhelmingly voted to approve the acquisition at their special meeting held on March 28.

We are still awaiting approval from the Federal Energy Regulatory Commission, which we expect we could receive at any time in the coming weeks.

We expect we will close the acquisition within 5 business days of receiving FERC approval.

And we look forward to quickly integrating the Crius portfolio into our existing integrated platform.

We have been working effectively with the Crius team on transition and integration and continue to be confident in the value of their retail portfolio.

Turning now to Slide 7. We are reaffirming our 2019 ongoing operations guidance ranges of $3.22 billion to $3.42 billion in adjusted EBITDA and $2.1 billion to $2.3 billion in adjusted free cash flow.

Our strong start to the year resulted in financial performance that was in line with management expectations for the quarter, setting up for what we expect will be solid full year results as we move into the important ERCOT summer.

While our first quarter results came in meaningfully above consensus, we are not resetting our full year financial guidance at this time.

There are a few important points to keep in mind as it relates to Vistra's first quarter performance.

First, this year, we had forecast internally that Vistra's retail margin would be higher in the first, second and fourth quarters of the year while lower in the third quarter as compared to historical performance.

This expectation is due to the extreme [peaky] nature of the 2019 forward power curve, with August heat rates forecast to be meaningfully higher than historical averages, thereby altering the comparative dispersion of annual retail cost of goods sold.

Second, as you know, the bulk of our wholesale earnings come in the third quarter of the year and meaningful retail EBITDA is produced in the non-summer periods.

As we have important earnings periods ahead, it is premature to alter guidance, even though we remain optimistic, especially with regard to strong pricing in ERCOT this summer given the tight reserve margin environment.

And one last reminder as it relates to our 2019 guidance.

We have not yet incorporated the expected contribution from the Crius acquisition into our numbers, but will do so following the closing of the transaction.

Beyond 2019, we continue to anticipate that our integrated business model will generate relatively stable earnings.

We still expect 2020 adjusted EBITDA will be relatively flat to 2019, which as you will recall is a marked improvement from Dynegy's premerger forecast.

Prior to the merger, Dynegy's forecast for 2020 and 2021 reflected anticipated declining EBITDA due principally to lower capacity revenues of PJM.

We now expect we'll be able to close that EBITDA gap as a result of improvements in forward curves, tight wholesale market conditions in ERCOT and enhanced management expectations for merger value lever achievement.

Creating earnings and cash flow profiles in consistent ranges is of critical importance to Vistra as we continue to attract new long-term investors to the stock.

We believe we will be able to achieve these consistent results in the future as a result of our diversified earnings profile, especially our retail business and capacity revenues where roughly half of our EBITDA is derived and in-the-money generation fleet combined with the execution of our hedging strategies by our commercial team.

Our retail operations also lead the charge in our ability to convert a significant amount of our adjusted EBITDA from ongoing operations into adjusted free cash flow.

We expect this conversion ratio will be approximately 66% in 2019, which benefits from the Dynegy free cash flow and tax value levers and is meaningfully higher than the free cash flow conversion observed in other commodity-exposed, capital-intensive businesses that trade at a considerably more favorable free cash flow yield.

Our strong free cash flow conversion profile supports our diverse capital allocation plan, which we announced in November of 2018 and is actively being implemented today.

As of April 25, we had executed a total of $1.053 billion of our aggregate $1.75 billion share repurchase program authorization.

As a result, we now have approximately 483 million shares outstanding as of April 25 an approximately 8% reduction as compared to the number of shares outstanding at the time of the Dynegy merger close.

We still have nearly $700 million available for opportunistic repurchases under the program.

So long as our stock is trading at the current high free cash flow yield and what we believe is a meaningful discount to fair value, we expect we will continue to allocate capital toward share repurchases.

Although our stock price is certainly moving in the right direction.

In addition, we paid our first quarterly dividend on March 29 of this year to shareholders of record as of March 15.

The quarterly dividend was $0.125 per share or $0.50 per share on an annualized basis.

We expect we will grow the dividend at approximately 6% to 8% per share annually going forward and can support this growth through disciplined investments, such as the Crius acquisition, the Upton 2 solar and battery storage project and the Moss Landing battery storage development opportunity.

And last but certainly not least, we believe we remain on track to achieve our long-term leverage target in a range of 2.5x net debt-to-EBITDA by year-end 2020.

As you have heard before, balance sheet strength is a core tenet of Vistra's operating model and we plan to manage our business and cash flows accordingly with the opportunity to continue to improve our credit profile which we believe strengthens our business and ultimately, our stock price.

We are seeing our view materialize that our diverse capital allocation plan will attract new long-term investors.

In the first 4 months of 2019, we have continued to withstand selling pressure from our -- 2 of our top 5 largest shareholders, Oaktree and Apollo, with relatively strong performance in our stock price.

We believe the stability in our valuation has only been possible because we have been able to successfully attract new investors into the stock.

As 2019 runs its course, we expect our shareholder rotation will be meaningfully complete, which should help to unlock the true value of Vistra's equity as we continue to meet investor expectation and execute on our financial and operational goals.

While we are making progress, it is our view that our free cash flow yield remains inordinately high and hence, our stock price very attractive.

I'm now on Slide 8. A topic I know has been at the forefront of discussion in our sector relates to expectations for the 2019 ERCOT summer as well as the logic behind the backwardated forward curves we are observing in the market.

It is our view that the backwardation of the forward curves is dislocated from market fundamentals, in particular beginning in 2021.

As you can see in the chart on Slide 8, which is based on the ERCOT Capacity Demand and Reserve report, or CDR, adjusted for the announced Gibbons Creek and Oklaunion retirements, reserve margins are forecast to remain very low through 2023, reaching levels that are less than half of the targeted reserve margin ERCOT recommends by 2023.

These anticipated lower reserve margins are a product of projected 2% annual loan growth in ERCOT combined with relatively low new thermal generation coming online over the next several years.

While both Vistra and ERCOT expect sizable new generation to be added to the market in the form of solar and wind assets, the intermittent nature and relatively low capacity factors of these assets is likely insufficient to offset the current shortfall of generation at ERCOT and the anticipated load growth in the state.

As a result, we expect that the supply and demand balance will continue to be favorable for the foreseeable future.

In addition, it is important to note that there remains 10,000 to 15,000-megawatts plus of thermal generation at risk in ERCOT that will likely act as a long-term supply and demand calibration feature in the market.

And given that the newbuild will likely be wind and solar coming in much lower megawatt increments, the market reaction and calibration should be quicker and less volatile, with a lower likelihood of the market getting overbuilt and resulting in prolonged depressed pricing.

Despite these implied tight supply/demand dynamics, ERCOT forward curves are materially backwardated with 2023 North Hub around the clock prices currently forecast to be nearly 30% lower than 2019 prices.

This level of backwardation is clearly dislocated from the market fundamentals and is likely a result of uncertainty with market participants driving a lack of liquidity in the out years.

In 2021 and beyond, for example, long dated power purchase agreements are currently setting the price of power.

This relatively small portion of transaction activity is not representative of where the market will ultimately settle as we get closer and closer to the (inaudible) period.

Ironically, it is the backwardated nature of the forward curves that should keep new thermal generation on the sidelines in ERCOT and to some extent, renewables.

Furthermore, as renewables build out in the West, there'll be congestions and discounted pricing, further inversely impacting newbuild economics.

Notably, Vistra is a net long generator, carrying at least 1,200 megawatts of length into the important summer months, some of which is used as a physical insurance against swings in retail load or to protect against an unplanned outage in our generation fleet.

The physical length we hold as insurance and keep unhedged in the summer is critical to minimizing our risk profile and reducing our exposure to the $9,000 megawatt hour price caps in ERCOT, which is an advantage we have over the many retailers who must manage their volatile ERCOT summer short position without physical [assets].

Turning now to Slide 9. I would like to spend a few minutes discussing the latest regulatory and legislative updates in MISO and PJM.

As many of you are aware, Vistra is supporting legislation introduced in the Illinois General by State Senator Michael Hastings and State Representative Luis Arroyo, called the Illinois Coal to Solar and Energy Storage Act.

Before I get into the details, I would like to emphasize that our support for this legislation is a reaction to the completely ineffective and dysfunctional MISO market construct, which has not improved after years of attempts by market participants.

This is very much in contrast to PJM and ISO New England, where both markets are functioning relatively well if not for unwarranted out of market activity, particularly the nuclear subsidies.

If our assets were in PJM and not MISO, we would not be discussing a similar form of legislation.

Moving on to the details.

If passed in its current form, the legislation would redevelop downstate coal plant sites into utility scale solar and energy platforms while also providing a path to responsibly retire existing downstate coal capacity.

While it's always difficult to predict the outcome of the legislative process in Illinois, we do believe that at least some or all components of the proposed coal to solar legislation have a reasonable opportunity to be included in a broader energy reform package.

The legislation is designed to help the state achieve its long-term greenhouse gas emissions reductions targets, incentivize local investment in communities and transition of the downstate generation portfolio without negatively impacting grid reliability, all while having a minimal total impact on customers' monthly bills.

We believe the various components of the bill adequately address the ultimate goals of interested parties and we look forward to supporting the legislation as it advances.

Also in MISO, we remain supportive of the amendment to the multi-pollutant standard that is pending before the Illinois Pollution Control Board and believe it will ultimately be approved by both the board as well as the Illinois Joint Commission (sic) [Committee] on Administrative Rules.

The amendment, if approved, would allow Vistra to manage the emissions of its downstate coal plants as one fleet with overall lower mass based tonnage caps.

These amendments would provide Vistra the flexibility to operate its fleet in a manner that is the most economic while reducing overall total emissions.

If the amendment is approved as drafted, which we suspect could occur in the summer timeframe, Vistra would be required to file with MISO to retire 2 gigawatts of nameplate capacity in MISO Zone 4 within 30 days.

MISO then has 26 weeks to perform their reliability analysis, which could put retirements in the late fourth quarter of 2019 to early first quarter of 2020.

We believe MISO's reliability analysis could conclude prior to the 26-week deadline and we do not believe any of the plants will be necessary for reliability.

Our preliminary analysis suggests that these retirements could be approximately $50 million to $100 million a year accretive to Vistra's long-term EBITDA profile, as some of our existing MISO assets are EBITDA and free cash flow negative in the current market environment.

We will keep you posted on the potential fleet rationalization as the MPS amendment progresses through the administrative approval process.

As for PJM, in April FERC approved a tariff change related to fastarc pricing.

The order would allow units that can start within 1 hour and have a minimum runtime of no greater than 1 hour to set the locational marginal price.

The order would also allow commetric prices to be reflected in wholesale energy pricing.

Even though the FERC order was ultimately more conservative than the tariff modifications requested by FERC, we believe the order is a positive step forward for price formation in PJM.

We estimate the impact of the order could be an improvement in around the clock prices by approximately $0.50 a megawatt hour, though it is difficult to discern how much of this benefit was already embedded in the forward curves.

Vistra's PJM generation fleet is well positioned to benefit from this pricing reform as Vistra operates a relatively young, low heat rate fleet.

We expect in general all of our baseload coal assets in CCGT should be online when the price adder is triggered and will realize the higher locational marginal costs.

While we do clear most of these assets in the day ahead market, we would expect the day ahead and realtime markets to converge over time.

And as forwards reflect the new price formation, we will have the opportunity to hedge into this uplift.

The changes are targeted to be implemented in November of 2019, so we do not expect a meaningful change to current year results, though the order is an improvement in the market structure, which is a positive for Vistra overall.

Similarly, reserve pricing reforms are currently in front of FERC as part of a PJM 206 filing which allows FERC to derive their own outcome in any final order.

The reserve pricing reforms would effectively allow all generating units providing reserves to be paid for this service.

And a related change to the Operating Reserve Demand Curve would set an administrative price for reserves under certain operating reserve levels.

Our very preliminary analysis suggests that these [potential] market reforms could lift around the clock prices of PJM by more $0.50 per megawatt hour.

As it relates to the status of the pending PJM capacity reforms, we still do not have any indication on when we might receive direction from FERC on this topic.

PJM has notified FERC of its intent to proceed with the next auction in August and we are supportive of this approach as it allows parties to continue to advance the ball for 2022 and '23 delivery year, although it does not address the price suppressive effects of the out of market activity, most notably the nuclear subsidies.

As I mentioned on the fourth quarter call in February, we continue to believe the outcome of the capacity reform process will be, at worst, neutral to the current state given FERC's view that the existing capacity auction construct is unjust and unreasonable due to the anticompetitive impact of out of market subsidies.

Action from FERC to neutralize these impacts will be even more important with the proliferation of nuclear subsidies that are becoming all too commonplace.

We continue to be perplexed how state elected officials can justify awarding subsidies to nuclear units that have shown no indication of economic need.

While there are certainly some nuclear assets that are economically challenged in the current market environment, it is our view that those assets are the minority.

Yet nuclear subsidies are being considered very broadly.

It is highly objectionable that the owners of these nuclear plants are holding the state-elected officials, utility commissions and employees hostage by threatening retirement of economic units.

We remain cautiously optimistic FERC will find a solution that appropriately neutralizes these subsidies, continuing its past practice of promoting balanced market reforms and supporting competitive markets.

FERC has historically played a strong and decisive role in protecting markets against actions that are unjust and unreasonable regardless of any perceived notion that the markets they are charged to oversee are perfectly competitive or not.

After all, what market is?

We believe it is highly likely the outcome of FERC's deliberations on this matter will result in a neutral to modestly positive impact on capacity pricing in PJM, especially given the more serious proposals in front of FERC.

For example, even the PJM FRR proposal deploys PJM-wide reserve margin in matching generation and load, which if deployed, would likely result in similar auction results to the existing market design, only potentially in a just and reasonable manner.

Properly designed MOPR would likely improve outcomes, but only modestly.

We should expect FERC to construct an order that creates a fairly functioning market, not an outcome-driven result that automatically improves pricing.

PJM has healthy reserve margins and the market has contributed to steady margin over the past several years of approximately $9 to $11 per KW month for combined cycle plan, an outcome we believe is reasonable and consistent under the circumstances.

What we expect FERC to do is to ensure the market does not further erode given the aggressive nature of the out-of-market activity.

In a nutshell, FERC must ensure just and reasonable markets despite state energy policies.

Last, there has been meaningful chatter in the market about Exelon and Illinois exercising an FRR option under current rules to completely carve out its ComEd load, serving this load with Exelon's nuclear unit.

For several reasons, we believe the potential risk of such an action to other generators have been overblown.

First, we do not see Illinois as even eligible for the FRR option under the existing rules as there is a requirement that a load-serving entity electing the FRR alternative demonstrate the ability to serve all of the load in its FRR service area.

Because Illinois has retail choice, ComEd does not serve all of the load in its service territory and is therefore not eligible to use the FRR alternative in our view.

Second, ignoring this complication, if the Illinois power authority were to run an auction to contract for the necessary resources, we believe it would be challenging for Illinois power authority to structure the auction in a way that would ensure the Exelon nuclear units are selected without running afoul of FERC's affiliate abuse rules.

If you assume, however, that Illinois is able to bridge these hurdles, we still believe any resulting impact of the residual ComEd zone in PJM would be relatively immaterial as Illinois would not only need to take out the entire ComEd load, but it would also have to cover the reserve margin requirement, which should result in the balance of the market being relatively unaffected.

Moreover, if Illinois is successful in pursuing its intent to rotate away from coal towards renewables, we believe the retirement of coal plants in ComEd and throughout Illinois could provide upside for ComEd gas plants on both the capacity and energy fronts, as dispatchable gas can take advantage of the greater energy price volatility that is typically present when baseload assets are replaced with intermittent renewables.

Given our approximately $175 million per year of PJM ComEd capacity revenue, any reasonable downside outcome would likely be in the $20 million per year range or less, which is relatively immaterial to our overall EBITDA profile.

In summary, we feel very good about the ERCOT market where we derive over 50% of our EBITDA and have a big seat at the table.

PJM and ISO New England have seen several changes in market design over the years, especially as it relates to capacity, but these changes have largely resulted in [proved] markets.

We expect that to continue but it will always be a hard-fought battle.

We also believe any downside scenarios in PJM and ISO New England are limited and less impactful to Vistra given the size of our EBITDA and the diverse nature of our revenue streams.

In fact, we expect MISO will be an upside after execution in 2019 and California has been a nice surprise to the upside for our portfolio.

We are also on track to add future EBITDA from the Crius acquisition and the Moss Landing battery storage project.

We remain optimistic about Vistra's ability to generate relatively robust and stable earnings in the years ahead, and we're not taking our eye off the ball.

I will now turn the call over to Bill Holden

Thank you, Curt.

Turning now to Slide 11.

Vistra delivered first quarter 2019 adjusted EBITDA from ongoing operations of $815 million with both the retail and wholesale business units delivering results that were in line with management expectations for the quarter.

Retail reported solid adjusted EBITDA for the quarter as a result of strong cost management and operational performance.

The generation segments also collectively finished the quarter in line with management expectations as March weather drove favorable results in ERCOT for the quarter, offsetting headwinds from a mild winter in PJM and New England.

These results underscore the value of Vistra's diversified business operations which can mitigate earnings volatility from external factors, such as weather or regulatory changes, supporting Vistra's ability to deliver stable EBITDA across periods.

Both segment results from the quarter can be found on Slide 15 in the appendix.

Also in the appendix, Slides 21 and 22 include our updated hedge positions for all markets in 2019 and 2020, reflecting an increase in hedges over the first quarter.

Our commercial team continues to take advantage of the volatility in forward curves to incrementally hedge at prices that we perceive to be attractive.

This hedging activity further supports our expected ability to generate relatively stable EBITDA over time.

Before I move off of this slide, I also want to highlight the meaningful increase in Vistra's first quarter 2019 results as compared to the adjusted EBITDA of the pro forma merged Vistra and Dynegy entities in the first quarter of 2018.

2019 results were nearly $240 million higher as a result of favorable realized prices in 2019, higher retail gross margin and the realization of merger value levers that continue to create value for our shareholders.

Finally, let's turn to Slide 12 for the quarterly capital structure update.

Vistra's long-term debt outstanding as of March 31 remained at approximately $11.1 billion.

We are still forecasting we will repay approximately $800 million of senior notes in 2019 as we work toward achieving our long-term leverage target of approximately 2.5x net debt-to-EBITDA by year-end 2020.

We will also continue to opportunistically optimize our balance sheet through refinancing transactions in the future.

And we are continuing to allocate capital towards opportunistic share repurchases under our previous announced share repurchase program.

We also paid our first quarterly dividend in March and announced a tuck-in retail growth acquisition in February with the planned acquisition of Crius, a transaction we expect we'll be able to close in the second quarter.

Our meaningful free cash flow generation is supporting this diverse capital allocation plan which we believe will continue to attract interest from new, long only investors in our stock.

We have been receiving great feedback on our business model.

And as you know, we take input from our debt and equity holders very seriously.

In the meantime, we look forward to focusing on execution and delivering on our commitments in 2019.

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

(Operator Instructions) Shar Pourreza with Guggenheim Partners.

So just on MISO to start off, a couple questions here.

So it sounds like, Curt, you remain confident that when the legislative session in Illinois ends at the end of the month, we should see a positive outcome with the Coal to Solar Act.

So the 2 gigawatts that would retire under the MPS agreement, should obviously the pollution board accept it, how and when could we sort of see an OPI update in the context of your accretion guidance you just highlighted?

Is it sort of a fourth quarter driver or could we see visibility sooner?

Yes, so a lot of things in that.

Number one is I will never predict the outcome of a legislative session, and particularly in my home state of Illinois.

So I would say this, Shar, that I actually think it's probably less than 50% that will get energy legislation in this session.

I think we're in May, the session ends within a month.

And I think it's -- things happen really quick with legislation in the state legislatures, but I would handicap it less than 50%.

But in Illinois, they have the veto session, which is in November.

And I do think there's a higher probability that something gets done on energy.

With the new governor and he's got other priorities, I just don't know that we'll see legislation on energy, which is not in the top 3 or 4 priorities of the state.

I'm not sure we'll get it done in this legislative session, but I think ultimately, in the veto session, we have a reasonable chance.

I mean it's hard to predict any kind of legislation.

I think this one makes a lot of sense because we're cycling out coal.

And in the state of Illinois, I think that's really what the state and the citizens want to see.

But we're also bridging the gap for down state markets where many of these plants are, are very small communities that need property tax base.

And so it allows for rotation of that property tax base.

And it's also in an orderly fashion where we make sure that the electricity market doesn't get shocked quickly with a significant amount of retirements and prices rise quickly.

So I think there's an opportunity there.

With regard to just OPI and the interrelationship that, that has with the overall MISO profitability, the way we see this is, is that we can either achieve OPI results which are -- with some of these assets, or we -- and to the extent that the OPI is not enough to reduce the negative EBITDA and the negative free cash flow to a positive situation, then we will retire those plants.

Either way, there will be a significant EBITDA improvement.

And I think we gave those numbers, that's $50 million to $100 million.

And then the last part of your question I think is around just generally the OPI update.

I think that is more of a probably a third quarter earnings call timing that we would probably talk about whether there is an increase -- a further increase in our OPI efforts.

I think things are going well.

And so I -- but we're not prepared yet.

As I've told you guys before, we want to prove this stuff up before we come out with it.

And I think we need between now and sort of third quarter call to get that done.

So I think -- I hope those answer all of your questions.

No, it's perfect.

And then just on -- around ERCOT.

Obviously, thanks for the incremental thoughts around the dynamics down there.

I know there's obviously been some [bitter] arguments and obviously it was somewhat of a healthy print for the quarter.

Sort of to what degree was the impact in the quarter from like sort of what you saw with the early March cold snap or additional sort of runtimes at Odessa and the West Hub peakers with access at (inaudible)?

Yes.

So I think most of it was really March.

That was really predominantly where -- the strength of the quarter.

We did have a good quarter.

Shar, I look at it like an NBA basketball game.

I mean you can look at the first quarter, but you better show up in the fourth because you're never going to know who's going to win until you get there.

But we like what we did in this quarter.

But I think it was really in ERCOT, it was a March-driven order for us, really.

Got it.

And then just lastly, on the capital allocation, $700 million is left in the buyback.

You've got a very healthy dividend that's in place now.

You kind of alluded to how you're thinking about capital allocation 2.0.

You did obviously highlight given where the stock trades, incremental buybacks are obviously -- they're out there.

How are you sort of thinking about potentially additional retail deals?

And when do you sort of plan to update on a new phase of your capital allocation strategy?

So good question.

On retail, I think we are optimistic, obviously, we'll close relatively soon on Crius.

I think I've said this before, that was the one acquisition that we wanted to do.

And when Crius came in play, we wanted to make that happen.

We were able to do that.

And it does advance us significantly in these retail markets outside of Texas; also helps us in Texas, too.

But I wouldn't expect that anything in particular in 2019 around any kind of retail acquisition.

What I think we're really focused on is we have the retail expansion strategy that we talked about before, which was an organic strategy.

And I think we're going to be focused, given that we now have this catalyst in Crius to accelerate that expansion opportunity, we think it's a very good base to do that.

So I wouldn't -- I don't know that they'll -- we'll see really any kind of deployment in acquisitions for retail in '19.

It's hard for me to say beyond '19 though when we get into '20 or '21 on retail because it is an area we'd like to grow.

And so if there was an opportunity that suit our fancy, we would take a hard look at it.

I think both retail and renewables are the areas where you could see the company expand through investment.

And -- but I don't know that there's any -- in both of those categories, there's anything big on the forefront.

I think this is going to be done more on a bit by bit basis for right now.

And in particular, given that '19 is really -- we really have earmarked what we're going to do with the cash in '19.

Later this year, we're going to obviously pay down a lot of debt.

We need to do that.

We are hell-bent on getting to this 2.5x range.

And then '22, we're going to pay down a lot of debt.

Any kind of additional cash we would have, we would always balance, as we always have, we'd balance between when we want to buy back our stock, which will be a function of where it trades, and whether we want to put it -- deploy it and invest it in the business.

And those -- that's an economic analysis and we'll do that at the right time.

I do believe though that we will be up for a discussion around capital allocation I think at the end of this year, probably third quarter, fourth quarter.

Because I do believe as we've executed on a big chunk of the capital allocation throughout 2019, we can then begin to talk about '20 and '21.

We'll be giving guidance on '20.

And we always like to give you guys a little bit of a preview of the following year.

So we'll give a preview on '21.

And in that context, I think the company also then needs to talk about how they're thinking about capital allocation.

So that's how I'd expect that timing to come out.

Abe Azar with Deutsche Bank.

So your estimates for the [first start] reform is PJM is well below numbers we've heard elsewhere.

How much of that is due to the revisions that FERC kind of required versus initial expectations from others being too high?

I think it's a fair amount of what the ultimate order came out to be.

I don't -- when we had done the work previously, Abe, our numbers were not that far off.

We were probably a little bit shy of what others were saying, but we were in that general ballpark.

I think it's really our interpretation of the order and the impact of the order which was the big reason why it's different than what -- the other estimates that are out there.

Got it.

And then do you have any updates on potential noncore asset divestitures?

And could that be a avenue to return some more capital?

Yes, good question on that front.

So look, we -- I guess I can talk about it now, I mean we took a look at it, and the market just wasn't there.

We don't feel like we have a gun at the head in terms of generating additional cash.

So we weren't going to do a diluted deal.

And that's kind of what we were faced with.

And I don't really want to get into what assets we were looking at because that can be disruptive to the workforce and all kinds of things.

We took a look out there.

We'll always constantly be in the market, assessing where the market is and whether there are what I'd call "nonstrategic assets" that we could part with if somebody's willing to pay more than we think they're worth.

But we didn't get to the finish line where we felt like the deal was sufficient enough for us to pull the trigger.

And so we felt like we'd rather run these assets than to do something that was dilutive and just not economic from our standpoint.

But I -- we're always open to, if there's a better use of capital and somebody thinks that something that we own currently is worth more in their hands, we're all ears and we will test the market from time to time.

Got it.

That makes sense.

And then just a small clarification on Illinois.

The $50 million to $100 million, I believe that was an EBITDA number.

Is there a corresponding free cash flow impact as well with the maintenance capital?

Yes, I -- on the free cash flow, hang on, let me -- just -- just a second what, just Sara you were going to say?

I was going to say they're not eligible for capitalization.

So you can (inaudible) cash flow are the same (inaudible).

Right.

Right.

Yes, that's what I was going to say.

Okay.

Thank you.

I'm glad I didn't say anything stupid, though.

So I think they're one and the same because the way it works, because these assets, we brought them over, we did not capitalize them because they had no real ongoing value, everything we spend on those assets, Abe, goes to expense.

We don't capitalize anything with regard to the MISO asset.

So the EBITDA and the free cash flow numbers are the same.

Greg Gordon with Evercore.

Sorry to beat a dead horse here, but I just want to be clear that I don't conflate the 2 different opportunities you're seeking in MISO.

Just resolving the multi-pollutant standard amendment issue, either through getting it and being able to optimize the fleet or not getting it and closing those units equates to that $50 million to $100 million?

Or is that -- the both of them together?

The coal, the solar and the multi-pollutant standard?

It's just -- Greg, I'm sorry, this is confusing, it shouldn't be.

But it's just the fifth -- or just the MPS and the optimization of the fleet.

The transition payment as well as any EBITDA we would get off of the solar and the battery storage facilities are all incremental to that.

So that is purely optimization of the fleet without any of the coal to solar and battery legislation.

No, it wasn't confusing, I'm just a little slow on a Friday after a 50 earnings.

The second question is you said you were going to give us an update, obviously '20 guidance and talk about directionally where '21 -- what '21 looks like later in the year.

I appreciate that.

But in the past, you've said that you thought your business model would support EBITDA in a pretty tight range without much backwardation going out through time.

I think if sell-side analysts would just sort of mark their models to market for the 5% decline in the forward curve in Texas we've seen since February that it would look like your EBITDA is backwardated.

So to avoid investors sort of -- how do you give investors confidence that they ought to not just rely on that forward mark?

Because you know the sell-side analysts have been -- even most investors tend to just use the mark.

The mark would probably show backwardation here, and I don't think that's the way you think that business is going to trend.

So can you give us a little help with that?

Yes.

So a couple things.

First of all, I think that's a very good question.

And so I tried to talk a little bit about that in the script, but I'll get into a little bit more.

I think we believe in ERCOT, for example, that '21, '20 and '23 that the backwardation in the curve is not fundamentally driven, but it's more transactionally driven by a very small portion of transactions in the market.

Meaning, it's thinly traded.

And we think it's a bit overdone out there.

I will tell you that prices are likely going to be lower in '21 and '22 and '23 than probably what they are in '19.

I think '19 is probably a peak of the low end of the reserve margin.

But that's all a function of what ultimately gets built.

But I do think that curve is a heck of a lot flatter.

So one thing is, I just think we're going to see higher contribution from the curves.

We also, as I've talked about many times, the market is going to ebb and flow, and we're going to have opportunities as the market increases and decreases pricing anyway in the forward curves based on views of tightness.

And we will be able to hedge into that.

I think we can construct a realized price curve that will be better, and we've done this historically, better than what you're seeing in '21, '22, '23.

The other thing is, is we have the Crius EBITDA.

We have the -- or not Upton 2, we have the Moss Landing and I'm sure we'll have some other things.

So I believe that there's some things already baked into the system, and then the MISO uplift of $50 million to $100 million.

So I'm pretty darn confident right now.

I wouldn't go out to 2023.

But I feel pretty good about -- remember, I've talked about this $3 billion plus number.

I think we can achieve the $3 billion plus.

And I've tried to make that case.

I mean we're not a sector, at least right now where the underlying product is growing much more than 2% in Texas and roughly 1% or less in other markets.

And so for me to sit here and try to tell you that we're going to grow off of what is going to be hopefully a very big number in 2019, I can't tell you that.

But what I've been trying to tell you guys is, is that we're a $3 billion plus a year EBITDA company.

And what's more important than that is we're going to drop down 65% to 70% of that to free cash flow, which is highly significant.

So I think that's really who we are.

I think we're a value play at the end of the day.

We've got a good strong dividend.

We expect to grow.

And then we're going to have significant amount of cash.

We can deploy some of that back into the company to grow EBITDA and return some of that to shareholders.

That's Vistra Energy, that's who we are.

But I do -- I stand by this $3 billion plus number.

And I feel like we will be able to hit those numbers, and that's what we're shooting for.

Julien Dumoulin-Smith with Bank of America.

Hello?

Can you hear me?

Yes, Julien.

I wanted to follow up on a couple items here.

So just from a timeline perspective, just wanted to understand your comments earlier about the updates with third quarter.

If it transpires that we don't have legislation in hand quite yet, right, given the veto session and all that in Illinois, and I know you don't want to necessarily predict that, but just in terms of providing updates, could we get an OPI update with the third quarter time frame even without some of the clarity in Illinois?

And then separately later on, whatever happens, get a separate and discrete update on the future of the assets then?

Yes.

Yes.

Okay.

One does not preclude the other.

Yes, okay.

That -- hey, we're just looking to clarify.

And then separately just to understand the process itself, how are you thinking about the implications of legislation just in terms of levers you have, focusing more on the PJM side of the equation rather than necessarily the MISO levers you have at present that you've gone over already?

Well, look, I mean you guys know this, that there's a -- the way it works in Illinois, there's a big player, and it's Exelon, and I know that.

And so Exelon is going to make some moves in Illinois.

We think what we're doing is consistent with the things they want to do, and so that's just the way Illinois goes.

And so I -- we don't have the big seat at the table that Exelon does.

What I do think they have is we have a very compelling, and I think fair proposal.

It's not a greedy proposal and it has a lot for everybody.

It has something for the local communities.

It has something for the environmental groups in terms of getting a certainty around what's going to happen with the coal fleet.

And it also has reinvestment in renewables where that's where the state wants to go.

And I think it's reasonably priced.

And in terms of its total impact on a customer bill, it's minuscule.

And so I think we have a -- what I would consider, we have a lot of good things in that legislation, which is why I think it has some strength.

It's yet to be seen where -- how high the support for it will go, but we've actually had really good reception on this legislation.

I'm going to Illinois to spend a couple of days here pretty soon.

I'll get a better read of that when I get there, Julien, and I can always -- we can pass that along through Molly and others when we get back.

But I think, that's why I said, I think there's a reasonable shot here, especially if a energy -- a broad energy reform bill gets moved in Illinois, I still think that's got a better chance in the veto session than this current session.

But if it does get moved, I think there's a really good chance that this could get tacked onto it.

And so that's why I feel pretty good about what can happen in Illinois.

And clearly, PJM is a bigger deal for us.

I mean we've got more megawatts.

Our retail business is going to end up being bigger there ultimately.

And so that means a lot to the company.

And so we -- when we emphasize our time, we spend a lot of time around PJM.

It's pretty simple.

I think -- I can't remember the numbers, but I think it's like 90-plus percent is -- comes from ERCOT, PJM and ISO New England, in that order.

And so we do spend a lot of time, and I'm spending time in Pennsylvania, I'm going to spend time in Ohio because of the nuclear subsidy efforts that are going on there.

And so we do put a lot of emphasis around PJM because it is important to our company.

A quick follow-up if you don't mind.

More of a detail question.

Just 1Q adjusted EBITDA, obviously straightforward.

How do you think about cash flow for the quarter just to get it out there, FCF?

Yes.

Julien, so adjusted free cash flow from ongoing ops for the quarter was $395 million.

Now that's about, I think a 48% conversion ratio.

But if you recall, we have some fairly lumpy outflows in Q1 that don't recur the rest of the year.

And those would include property tax payments and also the timing of annual incentive payout.

Steve Fleishman with Wolfe Research.

Just I know this is -- you don't necessarily know this information.

But just curious, Curt, if you have any sense on any updates on the selling shareholders and what we might see when they report holdings, I guess in mid-May?

I do know that the 2 large shareholders have -- and this is significant for our -- for the tax-free nature of the spin that we had when we basically -- when we became Vistra.

But I think they're both below 5%.

In terms of exactly where they are, Molly probably has a better sense of that.

I really -- Steve, I don't know exactly.

But Molly, would you have anything to add around kind of where they are?

I don't know their exact positions, but definitely they've both been selling in the first quarter.

Yes.

And we do know that -- that's the other thing, Steve, is that we know they've been active selling.

And so I just don't have the exact numbers.

But I expect that we're going to see a pretty material move in their holdings when, is it the 13Fs that come out?

I think we're going to see a pretty precipitous move here.

The nice thing I will tell you is that I think both Oaktree and Apollo have sort of settled into a selling operation, if you will, that's been kind of ratable, systematic.

And I think my own -- I don't talk to them about this, it's not my business, but I think we tried to do some large trades.

Those tend to send signals to the market.

They tend to be a little bit disruptive.

I will tell you that the banks that actually execute them sometimes get a little ahead of themselves and create issues.

And so they've kind of backed away from that, and they're doing this more in a very systematic way.

And I think because of that, we've seen that we've been able to sort of incrementally move the stock price up while they're doing that.

And I like that better.

But I think they've moved quite a bit.

I just don't have a guess at the numbers.

Okay.

One other question.

Just you and NRG had much different retail kind of outcomes this quarter.

I think it's mainly just due to the way they do their transfer pricing.

But just maybe if you could give a view of kind of just retail trends in ERCOT and just how you're seeing margins, customer account, things like that.

Yes.

So I'll speak just quickly on us and ERCOT.

I mean we -- or us and NRG.

NRG does more of an average transfer price and we do not.

We -- the pricing to retail is at market at any given point in time.

So we should see lower margin -- contribution margins in retail and EBITDA in the third quarter than what NRG will see.

And so I'm not at NRG, but that's just generally what we know about how it works.

And we like the way we do it, it seems they like the way they do it.

And -- but that is a difference, and I think that is a difference in this quarter for us versus them.

Not the only difference, but that's one of them.

In terms of -- what was the other question, was just...

Just overall trends, yes.

Just generally around retail.

I mean we did have a bit of attrition in the first quarter, but very small attrition.

We grew accounts last year.

We still feel like that we have a shot at having a pretty good year in terms of residential attrition in small business because we're going to see some really peaky pricing in the summer.

And sometimes what happens when that happens is that we tend to get customers coming our way.

And in our guidance we do have some net attrition, we always do.

We feel pretty good, in a higher price environment, we sometimes see customers come our way and we're obviously working toward that.

We'll see.

And then of course I think NRG said this and I think I would say it again is that you never know what can happen in the summer.

But some big books could come our way.

I did say that we're not looking to do any real acquisitions.

But sometimes, in this type of environment, if a retailer is not prepared well enough and we get some really spiky costs, we may see some opportunities to take on some additional customers from somebody that can't make it.

So that could come our way as well.

In terms of just margins, I would just say that our margins continue to be strong.

I think our team does a tremendous job on how we price and we're very cognizant of the attrition levels of our customers.

And so it's always a balance in terms of how much price you want to move someone up when wholesale prices go up and also being able to retain that customer.

We tend to take a long-term view.

But over time, we're able to move prices up as the market moves up.

And we've got a very sophisticated and analytical group that helps us think through what's the right time to do that.

Jim, I don't know if you have anything to add

Yes, Curt, the only thing I would add -- Steve, this is Jim Burke.

The market, all retailers entering '19 were facing a higher annual power cost entering '19 than they were facing entering '18.

That's on the order of about $10 a megawatt hour on a 7 by 24 basis.

And then when you shape it, and you got swing in ancillaries, it's about a $15 increase.

All of that was really showing up in third quarter pricing.

So as Curt said, we're trying to levelize our prices for our customers.

Our experienced quarter 1 '18 versus quarter 1 '19 power cost, since we are transferring at market, that did not vary much at all.

But our revenue was higher in Q1 '19 in anticipation of having to deal with this higher annualized power cost.

That's why Curt was emphasizing the margin for retail is really going to be in Q1, 2 and 4, because we're all climbing not only a rising curve, but a peakier curve in 3Q.

And so that's just a little bit of the financial dynamic that's different.

I would say that's generally true across all retailers.

The difference in intercompany may be if one company prices differently between segments.

And we do it on a monthly shape basis like the market unfolds.

Did that help, Steve?

Yes.

Your last question comes from the line of Angie Storozynski with Macquarie.

So 2 quick questions.

So on Waha, granted only a few of your plants really benefit from the weakness in this gas price.

But is there a way to actually tap into this -- the hub with more generation assets?

And then secondly, we've seen quite a dramatic move in RA prices in California.

How is it impacting Oakland's and/or anything around Moss Landing before you actually start building your battery?

Okay.

I just want to make sure -- we'll get to that last piece.

I think the first piece was around just the Permian Basin and the advantage pricing.

Angie, is that right?

And just kind of how that's -- how we think about that?

Yes.

I mean in the past, you've mentioned that there's a -- that you're working potentially on sourcing gas from Waha for more of your gas plants.

Yes.

So yes, okay.

So, well, as it relates to what's happening right now on the ground, first of all, I just -- I want to -- because I know there's been a lot of interest as to how much could this end up being in terms of this favorability in our guidance.

I mean I -- look, I will tell you that both Odessa and then our peakers that we have out there, our other plants have done well because we're actually getting paid in some instances to take gas.

It's not material enough because we just don't have as much capacity out there.

But I mean it is -- and when we build our guidance and our plans, and I think you guys know this, at the end of the day we have value that we expect to give because we're in multiple markets, we have multiple revenue streams and there's a lot of optionality in our fleet.

It's not necessarily defined, but we know we will achieve it.

And so part of that value in this particular year, that bucket I think is partly being filled by the fact that we have a better gas price or fuel price for some of those plants in West Texas than what we assumed in the guidance.

But that's filling up a bucket to get to the guidance.

And so that's why we're not moving things around.

Plus it's just not material enough to do that.

In terms of your question about can other plants benefit, the reality is right now, just because of the pipes, that benefit is exclusively in the Permian area.

We're not able to get that.

But we are advantaged with some of our plants because we see discount pricing off of some of the price points that we have.

It's still the case the Houston Ship Channel gas price, the units that use Houston Ship Channel gas price still set the price for power most of the time at ERCOT.

And we're able to access for many of our plants a discounted gas price relative to the Houston Ship Channel.

That's -- today, that's the reality.

That may shift a little bit as the pipelines get built and a lot of gas wants to find its way to the ship channel.

But that's also a function of LNG but also just the overall balancing of the system.

Because the system will be more balanced in that scenario because there's a heck of a lot more pipes down there than there are in the West Texas area, which is the real problem.

So I don't expect us to get a big advantage -- incremental advantage from Permian gas prices for our other feet that's outside of the Permian Basin in Texas.

But we already have an advantage at some of our plants because we have discounted gas pricing.

So that's -- so there was another question.

Yes.

So I was trying to gauge if there is a way for you to benefit from the recent move up in RA or capacity prices in California.

Well, I think -- we have.

So and that's -- in my comments, I probably was a little bit vague on it, but I talked about the fact that California has been a nice upside surprise for us, and it's really because of that.

But also there's been some issues around gas which has pushed up power pricing and we saw that last summer.

We may see that again this summer.

And so Moss Landing actually, for Moss Landing's EBITDA, we've seen a -- probably a roughly 20% increase in EBITDA off of just Moss Landing.

Less so at Oakland.

That's not really getting much of that.

And then of course, we still feel like Moss -- well, Moss Landing, we're working on, may have another opportunity at Moss Landing for another battery storage project.

And we've got a couple other opportunities at Oakland on that site for battery storage as well.

So what we like about California is, is we think we can create a reasonable EBITDA out of something that we didn't paid for and we didn't expect to really have much of an EBITDA.

But your point is exactly right and Moss Landing has benefited and we expect it to continue to benefit.

What we're finding is, and this is why we made the statement about Illinois, is these flexible combined cycle plants in markets that have significant intermittent resources actually can see times where they actually are used more and actually can see higher pricing.

Thanks, Angie.

I will now turn the call back over to Curt Morgan for closing remarks.

Thank you for taking the time to join us this morning.

As I stated at the beginning of the call, we do appreciate your interest in Vistra Energy and we look forward to continuing the conversation.

Thanks a lot.

Have a great day.

This concludes the Vistra Energy First Quarter 2019 Results Conference Call.

Thank you for your participation.

You may now disconnect.