Vistra Corp (VST) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Vistra Energy Third Quarter 2019 Results Conference Call.

(Operator Instructions) I would now like to hand the conference over to your speaker today, Molly Sorg, Vice President of Investor Relations.

Thank you.

Please go ahead.

Thank you and good morning, everyone.

Welcome to Vistra Energy's investor webcast covering third 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 David Campbell, 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.

We assume no obligation to update our forward-looking statements.

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.

We expect this call to be lengthier than usual.

We have a lot to cover, including Q3 results, 2019 guidance, 2020 guidance, with a glimpse of 2021, and operations performance initiative update and a 10-year view based on our detailed fundamental analysis.

So let's get started.

Turning to Slide 6. Vistra finished the third quarter of 2019 reporting strong adjusted EBITDA from its ongoing operations of $1.064 billion, results that are once again in line with the management's expectations for the quarter and results.

I am pleased to see relative to guidance that already incorporated high ERCOT wholesale power prices, especially for the summer of 2019.

The quarter began with an unseasonably mild July following one of the mildest Junes in over 10 years.

In fact, there was a very -- various sentiment out and there, and our stock had sold off.

On our second quarter call, we outlined why we remain bullish on the markets, especially ERCOT, and our company.

Of course, we know that August turned out to be a different story than July as the tight supply/demand dynamic in ERCOT resulted in sustained scarcity pricing.

We saw 12-, 15-minute intervals clear at the price cap of $9,000 per megawatt hour during the month.

To give you some perspective of the magnitude of the difference between July and August pricing at ERCOT, the average 7x24 price in August was $131 a megawatt hour, more than 4x higher than the average July settle price of approximately $30 a megawatt hour.

Our fleet performed well during the summer peak period, resulting in August favorability in our ERCOT generation segment, offsetting the headwinds from July and, importantly, bringing realized prices for the quarter back in line with management expectations for the year.

This is a key point and one I want to emphasize.

In ERCOT, in order for peak hour forward curve that is well above $100 per megawatt hour to be realized, the market has to see some level of scarcity pricing materialize.

In fact, for peak forward curves to trade at these levels, a certain number of scarcity pricing intervals are assumed.

In order to achieve financial projections that are based on the forward curve going into the year, we need to see some of these high-priced intervals occur.

In short, each high-priced interval is not necessarily additive to financial results on a stand-alone basis, and some of this volatility is required to achieve the expected outcome.

Scarcity pricing did materialize in August in ERCOT and September of this year.

And Vistra's integrated model performed well.

Our net length in ERCOT was able to capture scarcity pricing in the market, while also covering swings in our retail load, including the incremental Crius load we acquired on July 15.

Crius came to us, like many other stand-alone retailers, under-hedged for the ERCOT summer and right in the thick of it.

As a result, the Crius book was more exposed to summer volatility in 2019 than it would have been under our ownership.

In fact, the scenario that materialized this summer is exactly why we prefer to be net long in ERCOT.

Our incremental length is first available for risk mitigation to ensure we have the appropriate amount of generation available to cover forward sales from our generation assets and our retail load requirements.

Incremental generation is then available to capture any scarcity pricing in the market, providing upside opportunity.

Of course, the overwhelming majority of our generation position is used to hedge retail and much of the excess generation is hedged before we arrive at the prompt periods, creating a lower-risk, more stable earnings profile.

We believe this is the right way to run our business, especially in a market like ERCOT that exhibits such extreme volatility in energy pricing.

In fact, we expect we will see even more volatility in ERCOT in the coming summers as the market relies more heavily on intermittent renewable assets.

As a result, the types of volatility products that have historically been available for retailers are becoming more expensive and difficult to find.

Given the change in composition of the generation mix in ERCOT and the expectation for increased volatility, we will likely want to go into future summers carrying at least as much length as we have historically, a topic I will discuss in more detail momentarily.

Turning now to year-to-date results.

Vistra's adjusted EBITDA from ongoing operations for the first 9 months of the year is $2.586 billion, which is in line with management expectations that already incorporated robust summer wholesale power prices in ERCOT, as I previously discussed.

With our strong performance for the first 9 months of the year, combined with the addition of the Crius business as of July 15, and the Ambit business, which we just closed last Friday, November 1, we are both narrowing and raising the midpoint of our full year 2019 ongoing operations guidance range.

We expect we will finish the year delivering adjusted EBITDA in the range of $3.32 billion to $3.42 billion in the top half of our prior 2019 guidance range.

In effect, our base business is generally tracking as originally projected for the year, with Crius and Ambit providing EBITDA upside to our prior guidance range.

We are similarly narrowing and raising our adjusted free cash flow before growth guidance range to the top end of our prior guidance range of $2.2 billion to $2.3 billion.

Our improved outlook for adjusted free cash flow before growth is a result of the expected increase in adjusted EBITDA for the year.

You will also see in the guidance table, on Slide 6, a column highlighting illustrative guidance for 2019.

This illustrative guidance is $40 million higher than our updated 2019 guidance range as it backs out the negative impact of ERCOT retail backwardation we expect to realize in the year.

When we talk about retail backwardation, we are referring to the near-term impact of long-dated contracts executed with retail customers supplied by our native generation.

For example, if we execute a new 3-year contract with a retail customer, often the pricing under that contract is flat for the entire 3-year term.

Given the backwardation that exists in current ERCOT market curves, that usually means the contract is out of the money compared to the market in the early period of the contract but meaningfully in the money thereafter, such that the net present value of executing the transaction is favorable.

While we have historically realized some level of retail backwardation in our results, the total impact has typically been minor.

However, for 2019 and 2020, we are projecting a much larger impact as a result of the greater current backwardation entering into both years, coupled with increased interest by market participants to enter into long-dated contracts in ERCOT.

For 2019, we are estimating the impact of the ERCOT retail backwardation to be approximately $40 million.

If we were to exclude this negative in-year financial impact, our adjusted EBITDA guidance range would have increased to $3.36 billion to $3.46 billion, reflecting a midpoint that would have been at the high end of our guidance range.

We wanted to provide this illustrative range to give you a sense for exactly how well our integrated operations are executing in 2019.

In fact, we believe, excluding the adverse backwardation impact from 2019 adjusted EBITDA, is the proper way to look at our 2019 results, as we did not plan for the volume or the impact of long-dated contracts in our initial 2019 guidance.

And moreover, the future favorable impact from these retail transactions will be included in our prospective guidance range.

Our core business demonstrated stability in a volatile summer market.

And with the additions of Ambit and Crius, we are expecting incremental upside to our base results.

Turning now to Slide 7. We are also announcing today our guidance ranges for 2020.

We have been reiterating for the past year our belief that 2020 results could be relatively flat to 2019, in part because we were confident that historical 2020 forward curves remain dislocated from fundamentals and would improve after we got past the 2019 summer, a phenomenon we have witnessed in recent years as depicted on the next slide and one we expect to continue for the foreseeable future.

We have forecast summer reserve margin of 10.5%.

Summer 2020 is expected to remain tight.

And in March of next year, the loss of load probability in ERCOT's operating reserve demand curve shifts by another quarter of a standard deviation, which should further increase the probability of scarcity pricing intervals during the summer.

The recent uplift in the 2020 forward curve as well as the addition of the Crius and Ambit businesses has raised our prior expectation of relatively flat to a projected increase in adjusted EBITDA year-over-year.

Specifically for 2020, we are projecting adjusted EBITDA in the range of $3.285 billion to $3.585 billion and adjusted free cash flow before growth of $2.16 billion to $2.46 billion.

Similar to 2019, we have provided on this slide an illustrative guidance range, excluding the projected negative impacts of our ERCOT retail backwardation.

For 2020, we expect these impacts to be approximately $70 million higher than what we expect to realize in 2019, partially due to the addition of Ambit whose portfolio will also be impacted by contracts with retail backwardation in ERCOT.

Excluding these impacts, our 2020 guidance midpoint would be approximately $3.5 billion, a significant increase over our expected 2019 results.

In fact, many of you will recall the 5-year financial projections we published in our joint proxy statement and prospectus in connection with the Dynegy merger announcement in the first quarter of 2018.

At that time, our Board of Directors evaluated the merits of the Dynegy transaction, assuming the 2020 adjusted EBITDA of the combined business would be $2.81 billion, which included an estimated $350 million of value levers announced in connection with the merger.

The midpoint of our 2020 guidance is more than $600 million higher than that previous estimate.

In only 2 years, we have improved that 2020 financial outlook by more than 20%, with the vast majority of this improvement being driven by items entirely within our control and largely unaffected by commodity prices.

Specifically, approximately $425 million of the improvement in adjusted EBITDA is attributable to the hard work our teams have done to increase the expected merger value leverage by nearly 70%, while also adding incremental EBITDA through growth investments.

Two years ago, when we announced the Dynegy merger, the market was concerned about the long-term viability of this business, pointing to a $200 million decline in capacity revenues that would materialize in 2020.

The 2020 guidance we are providing today is just one example of the resiliency of this business model.

Our teams continue to identify efficiencies that maximize the value of our operations, and we have been successful at identifying tuck-in growth opportunities that are both EBITDA and free cash flow accretive with very attractive returns, while requiring modest levels of our free cash flow to pursue.

We are confident that this business model will continue to create value for our stakeholders, a topic we will discuss in more detail shortly.

And I must say, in our view, Vistra's stock price does not reflect the resiliency, stability and level of EBITDA and free cash flow of this business.

A final note on this slide.

You might notice that these guidance ranges are slightly wider than our prior guidance ranges, reflecting bands of $150 million as compared to our prior bands of $100 million.

We believe a guidance range based on a percentage of EBITDA is most appropriate and a range of plus or minus approximately 5% is reasonable and in alignment with peers.

We believe a wider guidance range also better reflects the potential range of outcomes for our business, particularly in ERCOT, with its tight reserve margins and increasing reliance on intermittent renewable resources.

This market dynamic is increasing the volatility in ERCOT as well as the potential to capture value if managed properly with the right assets.

In fact, it is now more important than ever that we have length on the days where there is volatility in the market, especially when taking into consideration the size of the load we serve.

As a result, we might find it prudent to carry more length in December 2020 and beyond than we have in years past.

Given this past summer and the likely influx of more intermittent resources, the cost of managing risk in ERCOT has gone up, especially for short retailers.

While the range of potential outcomes may be wider for us in ERCOT, we are well positioned to take advantage of the increased volatility, given our high-quality, long asset position, integrated business and commercial capabilities.

Furthermore, as I will discuss in connection with our 10-year outlook, our fundamental analysis continues to forecast a high probability of scarcity events occurring at ERCOT in future years.

The ERCOT market is changing.

Increasing intermittent resources will inevitably increase the appropriate level of reserve margin, a cost to run the power system with significant intermittent renewables that is yet to be fully understood and recognized by stakeholders.

This increased volatility suits our integrated business position and capabilities quite well.

So we remain bullish on the ERCOT market and our ability to capitalize on opportunities likely to arise in the future.

Turning now to our thoughts on 2021.

Directionally, we still believe 2021 adjusted EBITDA could be relatively flat to or higher than 2019 and 2020.

If you take a view based solely on the forward curves, 2021 adjusted EBITDA would look slightly down compared to prior years.

However, as we have discussed, and as we depict on the next slide, forward curves that are more than a year out tend to understate the tight supply/demand dynamic and increased likelihood of volatility in ERCOT in particular.

The graph on Slide 8 is a helpful visual of this phenomenon, where there was a significant uplift in forward pricing in 2018, 2019 and 2020, as each delivery year approached.

This uplift was especially prominent for 2019 and 2020, appropriately reflecting updated scarcity pricing expectations, including the modifications to the ORDC and the tight market conditions.

As you know, we develop our own point of view of where we believe forward pricing is likely to materialize based on rigorous analysis of market fundamentals.

As it did for 2020, our point of view for 2021 would suggest that current market curves are not representative of likely pricing outcomes.

As a result, when looking forward to 2021, in the context of our internal point of view, we believe 2021 adjusted EBITDA would exceed 2019 and 2020 results.

Recognizing that there are a range of potential outcomes for 2021, we are comfortable given our fundamental analysis that the 2021 has a very good chance of being relatively flat to 2020, if not, higher.

A relatively flat outcome would reflect a nearly $700 million improvement in the adjusted EBITDA that was forecast for the business at the time we announced the Dynegy merger 2 years ago.

The outlook for our business continues to improve, and we remain believers in our business model.

Turning now to Slide 9. I'm excited to announce today that we have identified $50 million of incremental EBITDA enhancement opportunities from our ongoing operations performance initiative under the leadership of Jim Burke.

Our teams on the ground know that in order to remain viable as the generation landscape evolves, we must ensure our assets are operating at the highest level of efficiency and at the lowest cost, while, first and foremost, prioritizing safety.

The OPI process is critical to our success in this regard, and it continues to deliver results.

Incrementally, within the fleet rationalization bucket of our OPI process, we have also improved our financial forecast with the retirements of 4 coal plants in Downstate Illinois.

As you know, Vistra was required to retire 2,000 megawatts of nameplate capacity in MISO Zone 4 in connection with an amendment to the Multi-Pollutant Standard, which was finalized this summer.

Three of the plants, Coffeen, Havana and Hennepin, were retired effective November 1. The fourth plant, Duck Creek, is scheduled to retire on December 15 of this year.

As a result of these retirements, Vistra has improved its 2021 adjusted EBITDA forecast by an incremental $100 million, which is net of the previously identified OPI opportunity at these sites.

Taken together, these updates improve our OPI target to a total of $425 million per year, up from the $125 million we announced in connection with the Dynegy merger.

Including synergies and OPI, the EBITDA value lever targets we have identified for the Dynegy merger have increased from $350 million annually to $715 million, which includes $290 million of traditional merger synergies, $325 million of OPI value levers identified and a net $100 million of EBITDA improvement in 2021 from the retirement of the 4 MISO plants.

It has been 2 years since we first announced the acquisition of Dynegy, and the financial benefits of the transaction continue to improve.

Financial synergies, however, were not the sole reason we made the decision to acquire Dynegy.

Another important factor was the opportunity to transition Vistra's generation fleet from one that was heavily weighted toward coal to one that is now approximately 64% natural gas by capacity.

We believe our relatively young, low heat rate generation fleet will be able to create value for our stakeholders over the next decade and beyond, which leads me to the discussion of our 10-year fundamental outlook.

Before I get into the discussion, I would like to explain why we believe it is essential for us to present a longer-term view of our company and the key power markets where we operate.

First, at a minimum, we believe it is important to frame the potential impact of our recently announced greenhouse gas emissions reductions targets on the business.

Furthermore, we believe it is imperative to our company's valuation that we explain the long-term prospects for the business given our perspective on technological and climate change impacts on the sector.

Simply put, there is a terminal value question for energy companies, and we believe it is necessary to address it head-on.

The good news is that the power sector stands to grow over time as a result of electrification across all sectors of the economy in response to climate change, and we are well positioned.

Slide 11 summarizes our 10-year view.

As most of you are aware, last week, Vistra announced for the first time our long-term greenhouse gas emissions reduction targets, which include our goal to achieve a more than 50% reduction in CO2 equivalent emissions by 2030 as compared to a 2010 baseline.

Notably, Vistra has already retired or announced plans to retire 14 coal plants and 3 gas plants since 2010, resulting in a reduction of CO2 equivalent emissions of approximately 42%.

As a result, in reflecting the marginal profitability of some of our coal units in particular, we expect we can achieve our 2030 emissions reduction target through incremental retirement actions, representing only 2.5% of our projected 2020 adjusted EBITDA.

While any such retirements will advance our progress toward our long-term emissions reduction targets, our fundamental analysis would suggest that future retirements of this magnitude will be warranted based on economics alone.

In fact, we estimate generation assets, representing approximately 5% to 8% of our projected 2020 adjusted EBITDA could be at risk of retirement in the next decade, predominantly from new build, in particular, renewables and expected environmental expenditures.

Importantly, this small percentage of our total EBITDA can be replaced with relatively minor growth investments over the same time period.

At Vistra's targeted return levels, we could replace a 2.5% EBITDA reduction projected to achieve our 2030 greenhouse gas reduction target with less than $500 million of investment.

The incremental at risk EBITDA would require only $500 million to $1 billion of additional investment.

To put this size of investment into perspective, we have already more than replaced the equivalent of the EBITDA risk through our recent retail and battery investment, not to mention, our incremental EBITDA improvement initiatives such as OPI.

In addition, this level of investment represents only about 2.5% to 7.5% of our anticipated free cash flow over the next 10 years, assuming we generate $2 billion of free cash flow each year on average.

The bulk of Vistra's current adjusted EBITDA is derived from its relatively young, low-cost, highly flexible gas field generation fleet, with 2 of the lowest cost nuclear coal plants in the country in Comanche Peak and Oak Grove.

We believe these assets are well positioned for success in markets, with the increasing reliance on intermittent resources.

In particular, we expect our flexible natural gas assets will run more and remain critical to the reliability of the regional power markets in which we operate.

We are seeing this phenomenon play out in California now, as the percentage of solar assets in the state increases.

For example, resource adequacy contracts for gas assets in California are being transacted at $7 to $7.50 per kw a month right now, which, as a frame of reference, is almost double the revenues awarded in the ISO New England's latest capacity auction.

We also saw this play out in ERCOT during the summer peak as our gas field peaking and steamer assets played a key role on low wind days.

Our fleet, which is approximately 64% natural gas by capacity, is well positioned to capture value and support market reliability as renewables are built out across the U.S.

Similarly, we believe our retail business will remain a stable and growing contributor of our performance over the next decade.

And we project fundamentals in both ERCOT and PJM, our core markets, will remain strong.

Turning to Slide 12.

Let's start our fundamentals discussion with ERCOT.

Getting right to the punchline, our fundamental analysis projects that ERCOT prices are likely to remain in the mid-$30s or higher per megawatt hour through 2030, with scarcity pricing events remaining a consistent feature in the market over this time period.

In reaching this conclusion, our team factored in an estimated 1.5% to 2% annual load growth through 2030.

And the scenarios that we evaluated included the addition of up to 50 gigawatts of new renewable assets, including approximately 6 gigawatts of battery storage with no sustained transmission capacity constraints, although we do expect there will be price differentials by zone.

We similarly modeled potential retirements in the market based on economic factors or plant obsolescence, assuming only 3.5 gigawatts of retirements over the next decade.

While we believe our analysis is conservative, if it proves to be too bullish, we believe there are more than 15 gigawatts of generation in ERCOT supply stack potentially at risk of retirement, which should further mitigate any downside scenarios.

In arriving at our conclusion on expected market price outcomes, we ran a bottoms-up hour-by-hour simulation model, with explicit assumptions around newbuild, retirements and load growth, and we calibrated our model relative to ERCOT's history.

What market observers perhaps do not appreciate is how markets will evolve with the rising intermittency from increased reliance on renewable assets.

The greater the percentage of renewable assets in the market, the higher the levels of volatility we expect to see.

This is true, even if the market has increasing reserve margins, as the expansion of reserve margins is driven by renewable assets, which tend to rise and fall together.

Renewable penetration effectively lowers the overall median price observed in a year as renewable assets with a 0 marginal cost shift their generation stack further to the right.

However, and most important, the higher percentage of renewables in the market will significantly increase the probability of scarcity events and pricing volatility, resulting in a significantly higher average annual price relative to the median price.

If you think about it, renewable assets of a like kind in the same geographic area will generally be available or off-line as a class.

In many instances, the renewable assets will not be able to capture price spikes because, in large part, they will be the cause of the scarcity event due to the correlated nature of their failure to perform.

For example, all solar will be off-line at 9:00 p.m.

and all wind drops when front stall over a geographic area.

An increasingly important metric to pay attention to in ERCOT will be net load, defined as load less renewables, as that is ultimately what the ISO has to manage on a delivered basis.

Net load peaks, rather than overall demand peaks, are expected to be more highly correlated with scarcity events in the future.

This was the case in ERCOT this August, when price play ups were driven primarily by low availability of wind generation on days with strong, though not extreme, demand, as we depict on the next slide.

Slide 13 shows that on August 15 of this year, power prices in ERCOT spiked to the market cap of $9,000 per megawatt hour.

However, peak load was less than 71,000 megawatts, approximately 5% lower than ERCOT's 2019 peak summer demand.

The real driver for the price spike was the low level of wind output, which was approximately 2,500 megawatts or less than 15% of nameplate capacity during the intervals at the cap compared to an average output of 6,000 to 7,000 megawatts for peak summer wind.

Renewable resources, by definition, are unpredictable.

With renewable assets forecast to make up a greater percentage of the ERCOT supply base over the next decade, market participants should expect sustained volatility as well as increased reliance on flexible and efficient natural gas assets, of which we have many.

In short, renewable penetration in ERCOT should not meaningfully depress market pricing.

Rather, our fundamental analysis would suggest average market price will remain stable to rising over the next decade.

Our ERCOT fleet, which is comprised of low-cost base load coal, solar and nuclear assets, highly flexible and low heat rate CCGTs and gas peaking and steam units is well positioned to capture value as the market evolves.

Before we leave ERCOT and move on to PJM, let's turn to Slide 14, where we backcast 2019 actuals to prior years in order to further demonstrate our view that 2019 is representative of ERCOT's new normal.

As you can see in the chart on the top half of the slide, despite the scarcity pricing we observed in August and September of this year, 2019 was not an outlier of extreme temperature days in Texas.

As I just discussed, the scarcity pricing was driven more by a combination of strong load and low renewables, a phenomenon we can expect to see more of in ERCOT over the next decade, particularly as a greater percentage of the supply base is comprised of renewable assets.

The bottom half of Slide 14 shows the result of recasting 2011 through 2019 based on our fundamental point of view of the 2020 supply stack.

The results reinforce our expectation of persistent scarcity events going forward.

For example, in 2018, modeling the 2020 supply stack, we would have expected to see 14 hours of North Hub pricing above $1,000 per megawatt hour compared to the 4 hours we actually observed in the year.

This backcast highlights that a small number of incremental renewable assets in the supply stack can have a noticeable difference in pricing outcomes.

Last, let's not forget that beginning in March of next year, ORDC pricing will kick in even earlier than it did in 2019, further increasing the probability of scarcity pricing outcomes.

We remain steadfast in our view that the long-term forward power curves do not reflect the underlying fundamentals of the ERCOT market.

As we have discussed in the past, the backwardation of the forward curve, while not reflective of fundamentals, do exert a certain level of discipline on the market, especially related to merchant thermal newbuild.

It will also impact future renewable development as we reach a saturation point for renewable PPAs.

Let's not forget that merchant investments require the ability to hedge 5 to 7 years out to secure capital.

In addition, the market must support sufficient revenues to justify merchant investments.

There are some that believe a round the clock pricing in ERCOT will decline to a sustained low 20s per megawatt hour, but this ignores the likelihood of incremental retirement at those price levels as well as the need to have long-term pricing that supports adequate returns for the lowest cost merchant investment, likely renewables.

In fact, this low price Draconian view is neither supported by any reasonable analysis, nor can it sustain the market in the long run.

Our analysis indicate that the current market rules in ERCOT can and will provide adequate revenues, but they will be more volatile and less predictable.

We will see if this market construct will support the level of investment, especially merchant, that will be needed to maintain a minimally acceptable reserve margin as we have assumed in our fundamental analysis.

We believe our existing ERCOT generation fleet, with assets that are low cost, flexible and well positioned on the supply stack will remain valuable and critical to ensuring a reliable, cost-effective risk.

Turning now to PJM.

I'm on Slide 15.

Unlike ERCOT, PJM has delivered relatively stable energy and capacity revenues over the last several years.

From 2010 to 2018, the average PJM CCGT earned approximately $9 to $12 per KW a month from the combination of capacity and energy.

In fact, capacity and energy revenues has historically moved in opposite directions, resulting in a relatively stable earnings profile in total and over time.

The graphs we depict on Slide 15 demonstrate this phenomenon.

For example, in 2016, you can see that trough capacity prices for RTO zone were offset by on peak spark spreads that were at a 4-year high.

Similarly, in 2017, on-peak spark spreads in EMAAC were relatively low, but capacity prices in the zone were at a peak in the second half of the year.

We have seen this dynamic play out in PJM over the years.

And in a similar fashion, our fundamental analysis result in expectations of flat to gradually rising overall energy and capacity pricing through 2030.

Our fundamental analysis is driven by the expectation of gradually tightening reserve margins, the possibility of slightly rising natural gas prices and prospects for ongoing retirement of older, less efficient coal, oil and gas steam units.

We also assume that the results in the capacity market will not change materially from recent clears, with expected highs and lows.

While we expect renewables will be added to the supply stack over the next decade, PJM is the least favorable market for renewables, with largely low onshore wind intensity and low sun irradiance.

As a result, we expect renewable development will be driven by state RPS standards rather than economics.

As reflected by the consistent band of historical returns in PJM, with over 180,000 megawatts of installed capacity, it is difficult for either incremental new supply or retirements to meaningfully move the market in one direction or the other.

Just as we have seen in recent periods, we expect total revenues to vary year-to-year, though to remain consistent with historical levels overall.

As it relates to Vistra specifically, we believe our large fleet of efficient CCGT units in PJM will continue to generate a significant amount of EBITDA for our consolidated operations as they collect significant revenue streams from both capacity and energy markets.

However, our PJM coal units could be at risk of retirement, just as other high-cost coal, oil and gas units will be over the next decade.

We have factored any potential future retirements into our EBITDA at risk analysis.

Which takes us to our last slide on our 10-year fundamental outlook, Slide 16.

Our analysis supports our view that Vistra can generate relatively stable to growing EBITDA in a wide range of scenarios, including generating approximately $2 billion per year on average of adjusted free cash flow before growth to either return to shareholders or to invest in growth opportunities.

If we invest, on average, $500 million a year on growth opportunities, roughly 1/4 of our projected adjusted free cash flow on an annual basis and achieve our targeted returns, we could deliver an incremental $90 million to $100 million a year of EBITDA.

Our track record, to date, with the acquisition of the Odessa CCGT plant in West Texas, the development of the Upton 2 and Moss Landing solar and battery project and the acquisition of Crius and Ambit on the retail side has demonstrated that we can be successful in finding high-return, tuck-in growth opportunities on a regular basis.

In fact, those projects have exceeded or expected to exceed our targeted return levels.

Continuing this history of executing on opportunistic growth projects likely in retail, renewables and battery storage would not only require only a small portion of our overall anticipated cash flows, but it is expected to result in a growing business that would more than offset the impact of potential plant retirements over the next decade.

In fact, even after allocating capital to growth projects and paying an annual dividend, Vistra could still have a significant amount of cash available to return to shareholders.

We expect we will have meaningful cash to deploy beginning in 2021 after we achieve our long-term leverage target.

As we always mentioned, with any discussion of growth, if we do not find opportunities to invest at attractive returns, we will return capital to shareholders.

This is always our litmus test.

In summary, our assessment of the 10-year prospect for our business reinforces confidence that our business model is resilient and compelling, taking advantage of the way we have positioned our company as a low-cost, low leverage integrated business with in-the-money assets in attractive markets.

We have covered a lot today.

I hope it has been a worthwhile discussion for you, and I hope you walk away from this call with a better understanding of a few key points.

First, renewable penetration is not an insurmountable threat to our business, rather a higher percentage of renewables in the market will merely change the distribution of price outcomes, placing more importance on unit performance during high price intervals and increasing the reliance of efficient CCGT assets and peaking units, of which, we have many.

And we will have the opportunity to invest in the technological changes impacting our business, but in a disciplined manner.

Second, while certain of our units, specifically our coal plants in MISO and PJM could be at risk of retirement over the next decade, these assets are not meaningful contributors of EBITDA today.

Our modeling suggests that given the favorable position of our generation assets on the supply stacks in the markets where they operate, only 2.5% of our estimated 2020 adjusted EBITDA would be lost in order to achieve our 2030 greenhouse gas emissions reduction target and a modest 5% to 8% could be at risk through 2030 from new build penetration and environmental expenditures.

The assets that are most exposed to a higher penetration of renewables are the older, high heat rate assets, of which we own very few.

And third, we expect to generate a significant amount of free cash flow on an annual basis.

Using only a small percentage of this free cash flow, we can make attractive growth investments to not only offset any EBITDA loss from future asset retirements, but to grow our business.

With our strong free cash flow and market-leading position in the core competitive electric markets in the U.S., we can participate in the evolving power markets where it makes sense, while also returning capital to shareholders.

We do not believe our business is a melting ice cube, rather, through cost management and efficiencies, financial discipline and execution, we believe we can continue to create value for our shareholders over the long term.

We continue to believe our stock is undervalued, and the math tells us that the market must be discounting our future value.

We believe this analysis is one piece of compelling evidence suggesting that we can produce strong results on a consistent basis over a long period of time, and we have demonstrated our ability to execute.

I will now turn the call over to David Campbell.

Thank you, Curt.

Turning now to Slide 18.

Vistra delivered third quarter 2019 adjusted EBITDA from ongoing operations of $1.064 billion, which, as Curt mentioned, is in line with our expectations.

Our third quarter results were $89 million lower than the same period of 2018.

The quarter-over-quarter decline was driven by lower prices and volumes in our Midwest and Northeast segments.

Lower retail gross margin in 2019 was offset by higher prices and margins in our ERCOT wholesale segment.

As you know, we are expecting negative adjusted EBITDA in our retail segment for the quarter, given the extreme peak in August 2019 heat rates observed in the market at the time we are procuring power for the year, which drove up our third quarter cost of goods sold.

As we discussed in our second quarter call, we shape the cost of goods sold for our retail business with the actual power curves rather than straightlining these costs over the year.

The retail backwardation that Curt mentioned earlier was concentrated in the third quarter.

The negative $40 million impact has already been fully recognized in the retail year-to-date results.

In fact, the negative impact in the third quarter is a little higher than $50 million, with some reversal occurring by year-end.

As you may recall, we realized higher retail gross margin in the first and second quarters of 2019 as compared to their respective quarters in 2018.

We expect a similar result in the fourth quarter.

Year-to-date, Vistra's adjusted EBITDA from ongoing operations was $2.586 billion, which is also in line with management expectations for the period.

The next 2 slides set forth our 2019 and 2020 adjusted EBITDA and adjusted free cash flow before growth guidance ranges.

Given that Curt already covered our guidance announcements, I won't spend much time on these pages, though I do want to mention the updates to our Asset Closure segment guidance for 2019.

You will see that our guidance ranges for the Asset Closure segment now assume a more negative impact as compared to our prior 2019 guidance.

The primary driver of this variance is the transfer of the 4 MISO plants retiring in the fourth quarter to asset closure.

This impact flows through the Asset Closure segment projections in the 10-year update we have provided on Slide 28 in the appendix.

It is important to remember that projected Asset Closure expenditures have already been accounted for in the asset retirement obligation on our balance sheet.

The retirement of the assets nearly buckets the anticipated cash flows in the Asset Closure segment as opposed to our ongoing operations.

Let's turn now to Slide 21 for an update on our capital allocation plan.

As of October 31, we've executed $1.415 billion of our $1.75 billion share repurchase program, leaving approximately $335 million of capital remaining for future share repurchases.

You will notice that the pace of our repurchasing slowed in the third quarter, which was a direct reflection of the improvement in our stock price during the period.

With respect to the $335 million that is outstanding under the program, we will continue to be flexible.

At the present time, our capital allocation priority for 2020 is debt reduction.

We are focused as a company on reducing our leverage in the range of our targeted levels, which will support an upgrade to our debt ratings and keep us on the path to investment grade.

We will continue to opportunistically evaluate repurchasing shares or investing in promising growth opportunities, especially those that have minimal impact on our leverage.

Our dividend is continuing as expected.

We announced last week that our Board approved the next quarterly dividend of $0.125 per share, or $0.50 per share, on an annual basis, which will be paid on December 30 to shareholders of record on December 16.

Following review and approval by our Board, we plan to announce the annual increase to our dividend on the fourth quarter earnings call on February 2020.

Management still anticipates the dividend will grow at an annual rate of approximately 6% to 8%.

Lastly, paying down our debt remains the key capital allocation priority for Vistra, and we are continuing to track toward our long-term leverage target of 2.5x net debt to EBITDA.

We believe achieving our long-term leverage target will further reduce the risk profile of our business for opportunistic growth investments and enhance our long-term equity value by increasing the value of the company available to shareholders and appropriately reducing the risk premium implied in our current free cash flow yield.

We continue to expect that we will have significant cash available for allocation in 2021 and beyond, supporting a growing dividend, future growth investments and meaningful excess free cash flow to return to shareholders, including repurchasing our stock when appropriate.

We expect to discuss this more as we progress through 2020.

One final comment before we open up the line for questions.

We have made a few changes to our hedge disclosures this quarter.

The new disclosures can be found on Slides 30 and 31 in the appendix.

Updates include the addition of power price sensitivities as well as a breakout of the hedge value that is embedded in our total realized price.

We continue to try to improve our disclosures to make them more user friendly, and we hope that you will find this new format helpful.

In closing, we remain confident that our business has the necessary elements to thrive now and for the long term.

The strong performance of our integrated operations during the third quarter reinforces our view that our business can generate stable EBITDA and free cash flow in a variety of market environments.

Our fundamental analysis supports that the core markets in which we operate will remain attractive over the next decade, and we believe our relatively young and efficient generation fleet, comprised primarily of lower heat rates, flexible gas assets, will be critical to supplying the nation's electricity needs as the country transitions to lower carbon technologies.

Our projected strong free cash flow generation will ensure that we can participate in this transition, where economics are supportive of investment.

We are excited for the future, and we hope you are as well.

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

(Operator Instructions) And your first question comes from the line of Shar Pourreza with Guggenheim Partners.

Just 2 quick questions.

First, Curt, could we get a little bit more color around the future investment, thinking about that might arise over the next decade?

I mean the annual investment of $500 million per year is sort of a big part of the growth story there.

Yes.

So I think we mentioned in the script, may not been that prominent, but I think we still view more near term that retail opportunities are the biggest opportunity.

I mean you guys can see that the value that we bring, and I'd say NRG probably bring to the table, given our capabilities and plus, in particular, given our long position, and we can take out not only just sort of the back office and other types of costs, but we can manage the commodity price risk exposure better.

And then there's just inherent in that, that difference, there's a much lower multiple for retail.

So we see some real value.

I think they're going to be smaller in nature though going forward, Shar.

I don't think there are many larger -- when I say larger, more in the Crius type, Ambit-sized deals out there.

But there are still other ideas out there that we'll likely pursue.

I do believe that we will participate at the right point in time in renewables and battery storage.

As you know, we have some real opportunities out in California to continue to build out our battery build at both Moss Landing site and our Oakland site.

I think we'll probably do some investment in that.

We have a good pipeline of opportunities on the development side, not only in Texas but also in a few other states where we have sites from some of our existing assets that will become available.

All that's going to be driven heavily by economics.

And I think you guys know, there's a lot of capital right now flooding into green investments by people who really don't have any business owning a wind project or a solar project, but they want to wave the green flag.

And I think that is -- the returns that we're seeing on that are pretty low.

I do believe that it's sort of like the CCGT buildout in the early 2000s, that there's going to be opportunities after the fact for us to take a look at it.

So I think when you think about the 10-year period that you mentioned, sort of early on, it's more of a retail focus.

I think it will be more on an intermediate period of time, there's going to be some opportunities around renewables and batteries.

And I'd also say that there may be a few little tuck-in opportunities inside of ERCOT on the solar front.

We've got a -- like I said, we got a pretty big pipeline.

We've got a lot of acreage and it's some really good acreage, but we have to be very selective around that.

To some extent, that will also be in support of our growing ERCOT retail business now that we've got the Ambit brand in here.

So there may be some opportunity to do a project or 2 around that.

But I think that's really where the growth is going to come from.

And I think we're just going to have to be patient and incredibly disciplined.

It's going to come, in my view, in a lumpy nature.

So this $500 million a year is probably -- I mean it's a great modeling exercise, but it's probably not exactly how it's going to happen.

Got it.

And then just lastly, Curt, I mean, obviously, the plan you presented today should provide a lot of comfort with the agencies, right?

The cash flows are sustainable, the EBITDA can actually grow, the balance sheet's healthy, you're definitely building a solid natural hedge with the retail business.

You've talked sort of in the past around your ratings in sort of 2 phases, right?

First, BB+; second, investment grade.

Can we maybe just get a little bit of a status on how the dialogue is going with the agencies; your sense on timing first around the notch improvement, and then second, investment grade, especially in light of how you're presenting your plan today?

That's it.

Yes.

So we're going to go in.

And I think we're going to go in and talk to the agencies because we're updating obviously.

We have a 10-year view, but we're also finishing up and taking to our Board in early December our updated long-range plan, which is our -- it's generally a 5-year view, and then we need to sit down with the agencies on that.

Moody's, for example, has asked for some of that information because I think they're going to go to committee.

I think they're going to talk about not only us but maybe others in terms of upgrading.

We've been on positive watch with them for some time.

So we think that in the next quarter or so, we should be in a pretty good position, hopefully, with all the agencies, especially with what we're presenting today, to potentially get an upgrade to that equivalent of BB+.

On the investment-grade front, that may be a little lumpier and probably, from that point, where we would get upgraded, probably a year -- a year beyond that before we get there.

I think with Fitch and Moody's, the metrics work pretty well at 2.5x.

And with S&P, because of the way they look at certain things, at the 2.5x, we're not necessarily exactly there on the metrics.

But with the business rating improvement, which we believe that we're squarely in line to get, that would put us in the investment-grade range.

So I think what we're really looking at is sort of first quarter 2020, we're hoping we're in that range of getting an upgrade across the agencies to that BB+ range.

And then we're looking at 1 year to maybe 1.5 years beyond that to get to investment-grade with all 3 of the agencies.

But I think that might be a little lumpier just given the way the metrics were.

So we're going to keep doing what we're doing because I think the more we execute, the more we continue to perform the way that we say and that this business model becomes more and more apparent to people just how strong it is, and then also the quality of our assets, the quality of our retail business, that's going to be really helpful with all the agencies because I think what really is the bigger hang up is, is this real?

Are people that -- are they going to be disciplined?

And does this business model work?

And I think -- so that's probably a bigger thing of anything.

And I think that takes a little bit of time.

But we feel like we're in line for this next upgrade in the near future.

And then we're going to obviously continue to execute, and we think we'd put ourselves in a good place for investment-grade rating.

Got it.

Congrats, Curt, on this execution.

It's terrific.

Your next question comes from the line of Stephen Byrd with Morgan Stanley.

Congrats on a very constructive and thorough update.

Okay.

Thanks, Stephen.

Good to hear from you.

Just wanted to touch on your point you raised about solar in ERCOT.

You gave a lot of good color around that.

I guess if you run a very simple sort of solar LCOE model, you could see that maybe solar could work in a $30-plus market.

But the point about practical limits on the growth of solar, I think, is a pretty important one we're often asked about.

Could you just add a little bit more in terms of the volumes that you see that's realistic in terms of actually getting a hedge, getting financing, et cetera?

Any color around that would be really helpful.

That's a good question.

So one of the things we've been trying to get our arms around, I think you guys know this, but the renewables that have been built in ERCOT, and frankly pretty much everywhere, have been PPA supported.

And it's been large players that have come in and allowed -- basically used their balance sheet to do PPAs.

And then it does allow, obviously, to get financing and take lower returns, right, especially if you got investment-grade counterparty on the other end.

But there is a saturation point where you start getting into smaller companies who don't want to own a wind project or a solar project.

And at some point in time in ERCOT, given the size -- I mean, we've got 50 gigawatts of renewables coming into this market.

I mean, that's more than half of the current nameplate capacity in the market -- some of that is going to have to end up being merchant.

I think the big question in ERCOT, being an all-energy market, as you add more intermittent resources and during the periods between when you actually see volatility in high pricing, prices are going to be lower because you're going to -- you've got intermittent resources with 0 marginal cost.

And so the question is, is there going to be enough revenue and enough frequency of that revenue to support merchant build?

And I don't care what kind of merchant build it is, it can be renewables or it can be combined cycle plants.

Now combined cycle plants are way out of the money.

Renewables that we see, when you run the numbers, if you can get proper leverage on them, can get decent levered returns currently, and I expect that they'll continue to see some cost decline in that, but once you get into the merchant side of things, because no one's really built a merchant solar plant yet in ERCOT, but once you start to do that in an all-energy market with a backwardation and the forward curves as steep as it is, it's tough to get the financing that you need.

And then you got to get someone to come in and put in the equity dollars.

And the problem with that, if it's just a single asset owner situation, it's going to be a little white-knuckle time between when you're actually getting lower in the off peak periods, lower megawatt hour pricing, and then you have to wait for a good summer to come in.

Some of my guys can do it because we can -- we've got a balance sheet and we can basically stand in between -- in between cycles.

But someone who's a single asset owner with leverage on top of it, it's going to be a real tough thing.

And I -- that's my biggest question is what's going to happen with the ERCOT market as you get more 0 marginal cost assets setting price for most of the hours and you see a much more volatile business?

Can you get the kind of development that's going to be necessary?

Because I don't believe you can build this 50 GW or so out with all PPAs.

I just don't think the market has that kind of depth.

So that will be an interesting thing.

My sense of it is, if we don't, there's going to be further changes to the market, whether it's an increase in the ORDC or even maybe some -- some changes to ancillary services to get more revenues in the market to make sure that there's enough revenues.

I mean I just don't see ERCOT going to a capacity market.

And when you think about outside of ERCOT, you do have capacity markets which can get additional revenues in.

And I think you hear Gordon van Welie say this in ISO New England because he's worried about the revenue stream from energy because of offshore wind coming in, but he still needs dispatchable resources, mainly the gas resources in New England, and there's nothing new getting built because you can't get a gas pipeline up there, so he wants to keep those around.

So he knows he's going to have to get revenues stream into the capacity market because that's the way to basically keep assets around and hopefully get some new builds.

So I -- I mean that's kind of how we see this playing out.

I mean it's going to be real interesting.

Obviously, we have a big seat at the table, so we'll be a part of that discussion, but that's sort of how we see it.

Your next question comes from the line of Greg Gordon with Evercore ISI.

Good update.

Thank you.

Just to be clear, you say -- you assume 50 gigawatts of new nameplate renewables in the Texas market.

I think that, that -- just that number alone will really cause people a lot of heartburn even if you're modeling that you can still generate stable cash flows out of that.

But just to be clear, that's your aggressive case scenario?

You don't necessarily believe that, that's where we're going to end up in 2030 given the constraints you just articulated?

Yes, I think what we tried to do, Greg, was this is a conservative view of the market.

We didn't want to come out with something that look very self serving.

And I just mentioned this, and I'll say it again, I'm not sure how this actually plays out.

I mean you can model things, and we sort of forced function some of this new build to happen.

Whether that can really happen or not on a merchant basis, I have a lot of questions about that.

And if that doesn't happen, you're still going to see increased volatility and higher pricing.

It's just going to be higher pricing than what we've assumed here.

And so I -- we don't really know.

I mean this is a modeling exercise.

We wanted to be somewhat conservative on it.

But there's a lot of leap of faith in this that, at some point, when the PPA market dries up, there's only so much depth to that, somebody is going to have to come in here and build on a merchant basis.

And that's tough in an all energy market.

And I don't see people like us or NRG or Exelon or others who have the ability to do it on balance sheet.

We've all seen what can happen in ERCOT if you overbuild the market.

So I just don't see that happening.

And then, of course, we mentioned in the script and I've said this before, there's still 15-plus thousand megawatts of higher heat rate, oil and gas and coal units, that if we did somehow overbuild, which I just don't see happening, would come out of the stack.

So that's why we're bullish on this ERCOT market, even in what we would consider a very conservative case that we put forward here.

Great.

My second question is you're obviously bullish on the fundamental value of the company and, to some degree, the arguments around the investment thesis in merchant power are this -- basically the durability of cash flow argument or the melting ice cube argument, which you're attacking head on.

But to the extent that you really believe you're going to generate free cash flow after growth investments that -- over the next 10 years, that's greater than your current market cap, why aren't you plowing further ahead more aggressively with the buybacks in the short to medium term?

And I know I understand that the very short-term answer is you want to get to investment grade, but to the extent you're confident that these cash flows are going to show up, we're basically looking at another $300-some-odd million of buyback in the short to medium term and then a pause in 2020 while you sort of run the engine to get to debt-to-EBITDA of 2.5x, right?

So how do you balance with investors who are saying, "Well, if you're so excited about the future, why aren't you being more aggressive with the buyback?"

Yes.

I mean that's a good question, and that's the balance that we're trying to strike here.

Look, Greg, there's no magic formula here.

And I think it's our judgment that the equity value of this company does better with a stronger balance sheet than not.

And there's also a credibility and commitment thing, and we're not just committing to equity here, we're also committing to people who own our bonds.

And we're trying to satisfy an entire capital structure here at the end of the day.

But I think I watch Calpine do this, and I know we're not where they were, but I watch them do a bunch of share buybacks and the market never believed their fundamental story, and their stock continued to decline as they bought back shares.

And I think that was just the risk premium that the market required because of the concern of financial distress of the business and the business model.

And so I said when I first got here that we needed to run this thing at a debt level that would put us in line to potentially be investment grade, and that's what we're going to do.

So I -- look, I understand that when you have debt that's even at 7.5%, and you're trading at a free cash flow yield of 15, the math I get, I just think that at some point we have to focus on getting our debt down.

And I think this is really a 1-year issue.

And then on the back end of 2020, I think what you'll hear from us is a discussion about what we're going to do in 2021.

And depending on where our stock is trading at that point in time, I would not be shocked that the Board would want to do some sort of a strong buyback program.

But I think what we are trying to tell you guys right now is that we do believe that following through on our commitment to get in that range of 2.5x is important for our company.

And we did outline it, I think, and David said it in his comments, I think there's a lot of reasons why the equity should be supportive of us doing that.

But it's a balance.

And you can make the argument that you've made here and others, but I think this is sort of what we believe is the right balance right now.

No, I actually completely agree with you.

I just wanted to hear you articulate it.

Your next question comes from the line of Michael Weinstein with Crédit Suisse.

Just a follow-up on the same line of questions.

I guess once you get a grade -- once you get an investment-grade credit rating and assuming that does improve valuation on the equity side as well, you've got really good cash flow, and from your own -- your own profile says there's sort of a limited amount of investment going forward, retail acquisitions will be smaller, I'm just wondering where -- what would you do with a better balance sheet and better valuations and better reception from investors at that point?

Where does the company go?

What can you do more that you can't do with the current cash flow profile, right?

I think we sort of outlined what we think is sort of the track of this thing.

And I wish I had a better sense of timing of it.

But we still believe in -- we still believe in the generation side of the business, we think it's still fundamentally important.

We're not going to a retail-only model and a short model.

And so I would expect us to put some investment predominantly on the renewable side because that's going to be the work for us.

But the other thing I will say that we haven't said a lot about but it's also part of this modeling thing was good for us, too, to understand kind of what's going on, but there could be some small investment in what I refer to as volatility assets, where either assets that actually can be around during the peak periods and they're very cheap type assets.

Now whether that's batteries or whether that's a gas fire peaker or something like that, we would look at.

But that's small potatoes.

I mean I think the real thing here is that you'll see our company invest in generation in the future as we retire generation.

And by the way, retirement of this generation is going to be needed anyway.

Most of these coal plants we're talking about are going on 60-plus years old.

They're becoming obsolete, and they're not economic.

And I think any business that is a capital-intensive business, whether it's airlines or chemicals or refining or whatever, have to replace their hardware at some point in time.

The question is going to be what kind of hardware are we going to replace it with?

I think it's going to be renewables.

And more important than that, it's going to be when do you do it?

And right now, I just don't -- there's so much money going into this that I think this is not the place.

I think retail is a better place for us to invest at this point in time.

And we'll see where the cycle goes.

But I think that at some point in time, though, there are going to be opportunities for us, whether that's PPAs to come off of the renewables and they become merchant and we have the capability to run them and see more value than somebody else, I really don't know how that's all going to play out.

But I do expect us to have a greater share of our business in renewables over the next 10 years.

Now whether we can spend that roughly $5 billion that we're talking about, $500 million a year over 10 years, I don't know.

If we don't, then we're going to return capital to shareholders.

And that's just the way it's going to be.

And we still generate a heck of a lot of cash.

I think what this thing shows you, this 10-year deal, which we think is very conservative, that if we don't put a dime back into the business, we're only losing 2.5% to maybe on average 6.5% of EBITDA, which means we're still generating a boatload of cash.

And so it's still a really vibrant business even if you don't reinvest in it.

So we don't feel like we have a gun on our head to actually go out and spend money.

And we're not going to do that.

But I think the good news on our company is we've got the scale and the capabilities.

I think we've proven that we can buy things and we can extract value that others cannot.

And I think we're going to get that opportunity around renewables.

It's just a question of when.

That makes sense.

We cover the renewable industry, and a lot of the retailers, the distributed renewable, distributed rooftop solar players, are growing at 15% a year of sales.

Do you see yourself maybe evolving into a retailer of perhaps, let's say, for example, centralized renewable energy, or perhaps maybe even a distributed power retailer, to compete against these rooftop players at some point?

I think that is something that we will consider and have considered and continue to consider.

I mean I think absolutely.

I think that is an area for our company that we will and have taken a look at.

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

I really appreciate the update.

Praful, thank you.

Curt, so maybe just on the investment that you've talked about over the next 10 years.

What I find is, in your position, having both a retail and generation, you have the opportunity to step in and buy assets rather than grow them organically.

I wanted to understand if that's a fair view.

Given the volatility that you're seeing or you expect to see, do you expect to be this opportunistic around acquisitions?

And what kind of examples can you give us where you kind of have seen that in the past and you expect to see that in the future?

Well, I think everything we've done so far, in my own opinion, has been pretty much an opportunistic thing.

I mean, I think what we did with the Odessa plant in Texas was a good example of, we had a view of the future and we had somebody that was not a natural owner of that asset that wanted to get out, and I think we were opportunistic.

And it turned out, obviously, to be a very good acquisition for us.

I would say that was part skill and part luck because we didn't know people are going to pay us to take natural gas.

But we did have a view that natural gas would be relatively cheap in the Permian to other hubs.

So I think that's an example of being opportunistic that I think we've been able to do.

I think the other thing is almost day 1, when we took over for Dynegy, we were in discussions with PG&E around a battery project in Moss Landing, which our predecessor owners were not.

And I think that was because we had the cash, the balance sheet and maybe the willingness, I don't know, to do something there.

But I think we will be opportunistic.

That's why I mentioned, Praful, that there could be some small asset things that would fit sort of, like I said, sit -- fit the profile of being a volatility type asset that we might take a look at that I think would be opportunistic.

Maybe somebody that owns it today doesn't seem to see the same value that we do.

And I think we'll continue to be that way.

And I believe that most of our renewable that I'm talking about, this renewable spend is going to be pretty much opportunistic.

It's going to be waiting for the right period of time.

And I've seen this business for a long time, and there are going to be opportunities around renewables where somebody overpaid, somebody can't make it, and those assets are going to come available, and we'll be around.

And pretty much all the deal flow comes through us in most of the markets that we're in, and we'll get an opportunity to take a look at it.

So I do think that the large portion of what we do and what we will do will be more opportunistic.

And I do think operating assets.

The one thing I like about operating assets, in particular retail, is they really don't have a lot of impact on credit ratings.

So you can do them, but they generate cash immediately.

The problem with the development, big development pipeline is you got that couple of year gestation period, and that takes a while and it's a drag on you until you actually get some kind of operating cash flow.

So I think we do lean a little bit -- plus just the cost to build something is higher than what the cost to buy something is, except I'm a little worried right now where the renewable side of things are with the number of players that have decided to enter at least right now.

Got you.

That's super helpful.

And I'm sure the balance sheet will also help you be opportunistic.

Just a second question quickly, and we've got this a lot, which is if there is a Democratic President, does this change your view in any way in terms of how ERCOT or PJM or how your assets are positioned?

How would you think about that?

Yes, that's a good question.

So again, I've been around a long time.

I've seen administrations come and go.

Because it's so difficult to actually make things happen, even when we've seen where we've had Republican-controlled Presidency, with a Republican-controlled Congress or Democrat-controlled Presidency and Congress, things just don't move that quickly.

And so I haven't really seen that big of a change.

There's been some things.

Obviously, the tax legislation was a pretty big deal for us as a company.

And I would say that, and there could be other things.

But if you talk about just what people are speaking about, there's a pretty big divide.

The current administration, in my opinion, is less of a principal administration and probably more -- I call them more opportunistic, looking for ways to actually surgically improve the economy.

On the other side of the equation, you see a fairly progressive group, and the front runners are fairly progressive.

And some of the things that I've heard, such as ban of fracking and just making it very difficult for gas pipelines, interestingly enough is actually good for our company.

We are a long natural gas equivalents company.

And so if you stop fracking, natural gas prices are going to go up.

That is good for our company.

It might make me think about I wish I didn't shut down the coal plants that we did because those are obviously natural gas equivalents.

I'm not sure everybody's thought that through yet, that you still have to run the power grid and you have to have assets.

And if you shut down gas drilling, that's going to increase electricity costs.

So -- but I've not really seen it change that much.

I don't expect it to change that much.

We're sort of agnostic when it comes to who's in the Presidency and the Congress.

I saw something recently where somebody came out and had us sort of pegged, I think, under Democrat Presidency and a Democratic control of Congress, that we don't do as well.

I just don't see that.

I mean, I -- and I also think we expect to be a participant in the renewable side of the business.

But one of the key points we tried to make in this discussion today is that when you bring in a significant amount of intermittent resources, you need some level of dispatchable resources that you can count on.

And right now, given where gas prices are in this country, natural gas, efficient natural gas plants fit the bill, and we purposely did a deal to get long those types of assets.

So we feel very good about how we've positioned ourselves.

And I feel like we will do well under any administration.

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

I just wanted to run by the illustrative '21 and how you think about that sort of a year-over-year walk, if you will, from '20.

I know you guys have laid out a number of different pieces there, but can we talk a little bit through it?

And especially given the context for the updated hedges, I just wanted to make sure I understand this right.

So looking at the hedges that you guys provided late in the deck, I think it's about $580 million for 2020, how do you think about that rolling off and rolling into '21?

That might be a different way to ask of like what kind of embedded hedge value putting in '21 as well?

Yes.

So first of all, I want to be clear that we don't provide -- we're not providing guidance on '21.

There's always -- we try to do this because I know people -- in particular, you, Julien.

I know that you care about that out year.

And so part of this is just to try to get people a window into it.

Admittedly, here's the story for '21.

I think we said this in the script.

If you market to market, just take the curve, we'd be a little bit below where we're coming in, in '20, which '20 is a pretty strong year, but we would be below that.

When we run our -- when we run a very detailed fundamental model for '21, and we did this last year, and we had the same viewpoint, at this stage right now, we would say that our fundamental view is above where the market is trading.

And so when we market to model, if you will, we would be above where 2020 comes in.

And if you stripped out the base business, if you stripped out the retail businesses, it kind of falls in that same line.

I mean we'd be a little bit below on the base business, but then on a mark to model, we'd be above.

The question is going to be are we going to see the curves move up?

And we try to show this because we've seen it.

I mean it has been very pronounced in '19 and '20, where when we rolled through the prompt period, the 1-year out period moved up.

As we went through the summer of '19, '20 moved up.

When we went through the summer of '18, '19 moved up.

And it happened as people began to realize that the market remained tight, but also they got glimpses of the volatility in the market, and we expect that to happen again.

But that's -- we tried to range that for you guys to say that.

But we feel pretty confident that we'll have an opportunity to hedge 2021, but I will tell you that we are going to be patient on that.

But what we typically do is we're usually 80% to 90% hedged going into any prompt year.

I don't expect us to deviate from that too much.

And I think we did try to say today that we might carry a little more length than we have in the past, one, because of the volatility and the fact that the volatility products that people have used to hedge swing risk in ERCOT are not as available because everybody's starting to realize this volatility but also because we added Ambit and Ambit also has swing risks associated with it.

So I don't know if that gets to an answer to your question, but I think we're going to be patient around '21.

We think it right now is below where fundamentals would see it.

And so I wouldn't expect us to move our hedge ratio up a lot right now in 2021.

But I do expect, as we go through the balance of '20, as we get closer to 2021, we'll be likely hedged about the way we normally are, somewhere between 80% and 90% going into that year.

Got it.

But just in terms of the year-over-year walk here, any other large factors to kind of keep in mind?

I just want to make sure I'm hearing you clear as you kind of think about your illustrative outlook.

Yes.

I mean just a couple of things that are a little bit different.

So when we go from '20 to '21, we'll have the battery facility out of Moss Landing, so that is included -- will be included in 2021.

We will get to a full run rate on Ambit and Crius because it takes us some time to do all the integration and all that.

And so that -- I think we've said before we're around $50 million on the battery.

I would expect us to a pickup of maybe $15 million to $25 million on the Ambit and Crius side.

So you are seeing some of that, that would show up, which is contributing to offsetting some of the lower curves that you have for '21.

Then if we mark the curves to our model, that's when you go above 2020.

But those are 2 things that are -- that will be coming on that are new.

And then we will be reaching full run rate of OPI in 2021.

So that $50 million will come on and then we'll be at full run rate by the end of 2021, but we'll be picking up some of that in 2021.

So those are the things that I would say are contributing to, right now, offsetting relative to the ERCOT curves.

And by the way, the PJM curves are down, they're backwardated and so is ISO New England.

They're smaller though impact on 2021.

And so the real swing on this -- and this is true of us pretty much all the time, is the real swing on this will be what does ERCOT end up doing?

And we feel very confident that our modeling is more representative of where things will come in, and that will obviously push us to either be flat, but more than likely higher, given all those other things I just went over with you, that we would end up being higher '21 to'20.

Your next question comes from the line of Sandeep Sama with Goldman Sachs.

I want to focus on retail for a little bit.

Did you guys notice any increase in customer attrition in the retail business from the volatility in the summer power prices?

Or would you say it's a little too early because of the long-term nature of those contracts?

So actually, we did not.

I mean, we actually saw sort of the opposite.

What tends to happen in a high price environment, our competition have to raise prices [intra month] because most of these guys are hanging on razor-thin margins.

And so when that happens, you tend to see people move from sort of the fly by nights, if you will, to safety.

And TXU Energy, obviously, is a safe bet.

So we actually saw through those months.

I think we actually grew customers during that period of time.

So -- and that's typical for us.

And the good news for us is when we get a customer, we typically could hold a customer for a good period of time.

So I think it was net-net beneficial to us over that period of time.

Got it.

The other question I had was on how important the IG rating is for you guys.

So as you think about achieving your leverage target of 2.5x, is it absolutely critical in your mind to crossover into the IG territory?

Or would you just be comfortable getting to that leverage level and maintain it going forward?

Yes, that's a good question.

Look, we never came out and said there's a fall in the sort of issue.

I mean what I do believe, and I think we've tried to say this, is that I think it's a strong indicator of the risk of the business.

And I still believe there is a risk premium that sits in our free cash flow yield because people are just uncertain as to whether the business model is sustainable, and the business is sustainable.

So we've tried to attack this in a couple of ways.

One is through just pure execution and discipline and doing the things we said, and part of that is reducing your debt.

I mean, I think that's one way to reduce that risk premium.

The other one is to try to draw a picture for people about what the long-term resiliency of this business is, which is why we did the 10-year view.

So the -- I would say the investment grade is less about credit spreads and more about the risk of the business overall, which I believe then translates into a higher equity value because investors view that they don't need the risk premium that they once thought they needed for this business, that the risk profile of this business is much lower, and they can own it at a 10% free cash flow yield, not a 15% free cash flow yield.

And I've said this a bunch of times.

This company trades at a 10% free cash flow yield at $7 billion plus of equity value.

I mean that's a huge change in the value of our company.

There's nothing I'm doing every day or anybody in this company is doing every day that could come close to creating that kind of value.

And so we're doing everything we can to prove to people because we believe it, that the business -- the risk of this business has changed substantially by the way that we run it.

And the amount of cash we generate is enormous.

It was -- who would have known?

It was embedded in this situation where people had too much debt and they were blowing money on bad things at the wrong time.

And we've cleaned that up.

I think we just have to do it year-over-year, which we're doing.

But I think a part of that puzzle is getting our debt down, and investment-grade would be a visible, tangible sign that the business risk of our company is significantly lower.

And I think that would have some impact on our free cash flow yield.

And there are no further questions at this time.

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

Once again, thank you for taking the time to join us this morning.

I know it was a long call.

Really appreciate the questions and the opportunity to talk to you about our business.

It's always a risk when you talk about 10-year view, but we thought it was important.

I think we've explained why we think that is important.

And we always appreciate your interest in Vistra Energy, and we look forward to continuing the conversation.

Thank you and have a great day.

Ladies and gentlemen, this concludes today's conference call.

Thank you for participating.

You may now disconnect.