Vistra Corp (VST) 2018 Q4 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the Vistra Energy 2018 Results Conference Call.

(Operator Instructions) Thank you.

Molly Sorg, VP Investor Relations at Vistra Energy, you may begin your conference.

Thank you, and good morning, everyone.

Welcome to Vistra Energy's investor webcast discussing 2018 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-K and the related earnings release.

Joining me for today's call are Curt Morgan, President and Chief Executive Officer; Jim Burke, Executive Vice President and Chief Operating 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 the 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.

Turning to Slide 6. I am happy to announce today that Vistra concluded the year reporting adjusted EBITDA from its ongoing operations of $2.809 billion, results that are both above consensus as well as slightly above our 2018 guidance midpoint of $2.8 billion.

When compared against our original 2018 guidance which utilized October 2017 curves, we finished the year more than $180 million above the comparable midpoint.

Vistra achieved these results through strong cost management across all markets which helped to offset a relatively mild August in ERCOT.

In fact, as you can see on the next slide, Vistra finished 2018 $25 million ahead of plan on achieving its Dynegy merger EBITDA value lever targets, $20 million of which we realized in the year.

This relentless focus on cost management flowed through to various capital projects we had forecast for 2018.

The Vistra operating teams exhibited meaningful CapEx spending discipline throughout the year, enabling Vistra to achieve ongoing operations adjusted free cash flow before growth of $1.611 billion, results that were $61 million above the high end of our guidance range, reflecting an EBITDA to free cash flow conversion ratio of nearly 60% for the year.

Since the close of the Dynegy merger in April of 2018, we have developed an understanding of the operations and maintenance expenses and capital expenditures necessary to maintain the fleet of generation assets that we project will allow us to uphold this spending discipline into the future.

Including the cumulative impact of the partial buybacks of the Odessa power plant earnout, Vistra's adjusted EBITDA from ongoing operations would have been $2.791 billion and its adjusted free cash flow before growth from ongoing operations would have been $1.589 billion.

As a reminder, when we executed the Odessa earnout buybacks, which we view as a growth expenditure, the economic benefit, net of the premium paid, was approximately $25 million which we largely locked in around the time of the buyback execution.

Before we turn to our Dynegy merger synergy tracking update, I want to briefly highlight our recent retail growth initiatives.

As I am sure you are all aware, earlier this month, we announced that we executed an agreement to purchase Crius Energy Trust, a retail energy provider with approximately 1 million residential customer equivalents in 19 states and the District of Columbia.

We estimate the purchase at approximately 4x EV to EBITDA, and we project the acquisition will be immediately accretive to EBITDA and free cash flow per share.

The transaction meets our internal investment return threshold and is expected to further improve our free cash flow conversion ratio, as we estimate the Crius portfolio will convert approximately 90% of its EBITDA to free cash flow.

As I'm sure everyone on this call is also aware, we did increase our purchase price for Crius due to an unexpected and hostile bid for the company.

While unfortunate, especially because this hostile bidder had an opportunity to be the successful bidder in the competitive auction process conducted by Crius leading up to the signing of our agreement, we continue to believe Crius is attractive to Vistra at this new price point.

It is not our desire to get into a bidding war.

We have put in place stronger breakup protections, and together with Crius, are moving quickly to obtain all necessary approvals, including the shareholders' approval to close the transaction, both of which support our bid over any potential future hostile one.

Any hostile bidder that would step into the process now would have to justify the higher price, including the increased termination fee and the delay in the approvals in overall closing time line, a tough thing to accomplish in our view.

I would also like to emphasize that we are fully prepared to take any necessary legal action that we believe is available to us, to defend our acquisition of Crius against any efforts by the hostile bidder to disrupt and interfere with our acquisition.

Jim will provide more details about this transaction later on the call, but suffice it to say we are very excited about the quality of the Crius portfolio and its strategic fit with our existing integrated platform.

Last, I am excited to announce that our retail team grew organically residential customer counts in ERCOT by approximately 15,000 customers in 2018.

This is the first year the team has achieved net growth on an organic basis since 2008, a tremendous outcome for the team and further proof that our marketing programs and customer satisfaction and service efforts in the ERCOT market have been effective.

Let's now turn to Slide 7 for an update on our progress achieving the Dynegy merger value lever targets.

On our last earnings call in November, we increased our synergy value lever target to $290 million from $275 million and we increased our operations performance initiative value lever target to $275 million from $225 million.

We are reaffirming these EBITDA value lever targets today, anticipating we will achieve the full run rate of $565 million EBITDA per year by the end of 2020.

I am happy to report, as you can see on Slide 7, that we finished 2018 tracking ahead of schedule capturing these merger value levers, realizing $195 million of EBITDA targets in 2018, ahead of our initial forecast by $20 million.

We achieved a run rate of $385 million by the end of 2018, $25 million ahead of our plans.

Last, as a result of our latest balance sheet optimization transaction that closed earlier this month, we have increased our forecast annual after-tax free cash flow benefits by another $15 million to $310 million.

We continue to believe there could be upside to the $275 million OPI target, so stay tuned for further updates on this topic in the second half of the year.

Moving on to 2019.

As you can see on Slide 8, we are reaffirming our 2018 adjusted EBITDA and adjusted free cash flow before growth guidance for our ongoing operations.

We are calling 2019 the year of execution, as we complete the full integration of the Dynegy merger and capture the value levers, implement our capital allocation plans and hit our targeted numbers.

Of course, closing and integrating Crius will be important as well.

We do not expect to update 2019 guidance to reflect the pending Crius acquisition until after the acquisition closes, which we estimate will be in the second quarter this year, perhaps even as early as April given that the Crius unitholder vote is scheduled for March 28.

And as I mentioned earlier, the teams have already filed for the regulatory approvals.

We do not expect any issues with obtaining regulatory approvals from the DOJ or FERC.

Importantly, our 2019 ongoing operations adjusted EBITDA guidance range of $3.22 billion to $3.42 billion and our 2019 ongoing operations adjusted free cash flow before growth guidance range of $2.1 billion to $2.3 billion, represent a free cash flow conversion ratio of approximately 66%.

As Bill will discuss later, we are significantly hedged in 2019 and have materially increased our hedges in 2020.

We purposely have dry powder available in ERCOT in 2020 given our expectation that the more significant move in ERCOT prices due to the ORDC change will occur in that year.

I have said it before and I'll say it again, the 66% free cash flow conversion ratio is a highly attractive feature of our company and significantly higher than that of other commodity-based capital-intensive energy industries.

As a result, we continue to believe that Vistra's valuation should shift away from the historical EV to EBITDA multiples which no longer reflect the value proposition of the sector, toward a free cash flow yield valuation metric at a proper yield.

We believe our future valuation will eventually reflect this new reality, as the financial markets continue to gain confidence in the new integrated power company model with the attractive features of low leverage, low cost and industry-leading retail operations, paired with in-the-money generation, all leading to relative earnings stability.

Beyond 2019, we anticipate our integrated business model will enable us to continue to realize relative earnings stability as we are expecting 2020 adjusted EBITDA to be approximately flat to 2019.

Our expectation for generally consistent adjusted EBITDA year-over-year is a marked improvement from Dynegy's premerger forecast, which reflect a declining EBITDA in 2020 and 2021 due principally to lower capacity revenues in PJM.

Through curve improvements, changes to the operating reserve demand curve in ERCOT and enhanced management expectations for merger value lever achievement, the previous Dynegy declining EBITDA forecast now reflects expected EBITDA strength and stability.

In the near term, we are continuing to focus on achieving our financial and leverage targets, returning capital to shareholders and meeting or exceeding our merger synergy targets.

As it relates to returning capital to shareholders, our capital allocation plan remains on track.

As of February 15, we had executed a total of $937 million of our aggregate $1.75 billion share repurchase program authorization, slightly ahead of where we thought we would be at this point in time because market technicals gave us an opportunity to repurchase shares at an attractive price at the end of 2018.

We now have 486 million shares outstanding as of February 15, a 7% reduction as compared to the number of shares outstanding at the time the Dynegy merger closed, with $813 million still available for opportunistic repurchases on the program -- under the program.

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

We also announced earlier this week that our board has declared Vistra's initial quarterly dividend of $0.125 per share or $0.50 per share on an annualized basis.

The dividend is payable on March 29, 2019 to shareholders of record as of March 15, 2019.

Management expects to grow the dividend at an annual rate of approximately 6% to 8% per share.

As a reminder, the payment of the dividend of this size represents just more than 10% of Vistra's forecast 2019 free cash flow before growth from the consolidated business and less than 35% of forecast 2019 free cash flow before growth from our stable retail operations.

We believe our targeted 6% to 8% per share dividend growth rate is supported by our projected free cash flow, including tuck-in EBITDA growth initiatives, such as our recently announced Moss Landing battery storage project and the Crius acquisition.

Importantly, the Crius acquisition is not expected to delay Vistra's achievement of its long-term leverage target of 2.5x net debt-to-EBITDA by year-end 2020.

Balance sheet strength is a core tenet of Vistra's operating model, and we plan to manage our business and cash flows accordingly.

We believe the execution of our diverse capital allocation plan will continue to attract new long-term investors while providing our shareholders with an attractive total shareholder return over the years.

In fact, we now consider 15 out of our top 20 shareholders to be long-term investors, and Vanguard and Fidelity are now our second and third largest shareholders, respectively, replacing Apollo and Oaktree.

Before I turn the call over to Jim to discuss highlights of our planned Crius acquisition, I would like to spend a few minutes giving a market update.

In January, the Public Utility Commission of Texas approved important updates to ERCOT's scarcity pricing formula known as the Operating Reserve Demand Curve or the ORDC.

The update simplified the ORDC from 24 different curves for different seasons and time of day to a single curve and shifted the loss of load probability by 0.5 standard deviation in 2 steps, 0.25 of standard of deviation in 2019 and another 0.25 of standard deviation in 2020.

What all this means in plain English is that the market participants should expect to see modestly higher prices during peak periods as the scarcity pricing formula should now better price in the risk of load shedding events.

The goal of the market changes was twofold: to better reflect significantly higher reliability risk in the market, as well as to provide better price signals with an aim to help avoid additional retirements from marginal generators and to support new investment in generating capacity.

We are fully supportive of the market changes and ensuring ERCOT has sufficient generating capacity to meet Texan's demand for electricity is critical to the reputation of the growing Texas economy.

We estimate the potential impact of these changes to the around the clock forward curves could be approximately $2 to $3 per megawatt hour in 2019 and approximately $3 to $4 per megawatt hour in 2020, modest overall increases in price that should support generation investment in the market while not meaningfully increasing the price of power to Texan consumers.

It is difficult to estimate the potential impact of these changes to Vistra as it is difficult to discern how the forward markets have already responded and will react in response to the new market design.

Assuming the market fully values the impact of these changes and appreciates the risk inherent in the tight reserve margins forecasted, we expect Vistra could see upside in 2020 where we are much less hedged than in 2019.

In fact, some of the improved 2020 outlook that flattens EBITDA is due to the ORDC improvement.

We have hedged some of our open position as we believe the 2020 forward curves had moved up in anticipation of the PUC's potential action, especially prior to the action, as there was speculation of a larger move.

We believe this action by the Public Utility Commission of Texas was a necessary step to ensure the long-term success of the Texas competitive electric market, and we continue to like our meaningful position in the ERCOT market, where we forecast we will derive more than half of our EBITDA in 2019.

It is the right move, balancing the need to support new and existing assets and costs to customers, with the end result of maintaining a healthy supply/demand balance.

Another market update has occurred since our last earnings call, the clearing of the most recent ISO New England capacity auction.

This year's auction cleared at a price of $3.80 per KW month, down from $4.63 in the last year's auction.

Despite the lower price, Vistra cleared nearly 500 more megawatts in the current auction, making the estimated negative impact at Vistra of the lower clearing price approximately $16 million or less than 0.5% of Vistra's forecast 2019 adjusted EBITDA from ongoing operations.

While the lower clearing price in the auction is certainly not ideal, it is relatively immaterial to Vistra given the diversity of our revenue sources from energy capacity and retail in multiple competitive electric markets across the U.S.

More fundamentally, we continue to be confounded that anyone would be able to raise capital to advance a new gas plant in ISO New England at a capacity price of only $3.80 a KW month.

As many of you know, a new 650-megawatt combined cycle plant cleared the latest capacity auction for calendar years 2020 and 2023.

I cannot emphasize this point enough.

Since the restructuring of the power markets began in the late 1990s, we are hard-pressed to find merchant power plants where the original equity owner received an adequate return and many suffered financial distress and bankruptcy.

Rather, it is the developers who earn sizable upfront fees to site, permit and construct new thermal resources that make money, leaving the third-party debt and equity investors owning an uneconomic asset.

One can only hope this reality will start to sink in with the financial community so debt and equity investors stop making irrational investments like this latest gas plant slated for development in ISO New England.

Our analysis suggests that the entire equity and likely some portion of the debt will be underwater the day the ISO New England plant is put into operation, if it ever is.

In our view, something is wrong with a market design that allows a plant like this to clear and suppress prices with a high probability it never gets built.

The last relevant market update is, of course, the status of the pending PJM capacity auction reforms.

Unfortunately, we don't have much to say on this topic as the devil will really be in the details after we hear from FERC.

However, we continue to believe the outcome of any capacity market reforms will be, at worse, neutral to the current state.

Recall that in June of 2018, FERC labeled the existing PJM capacity auction as unjust and unreasonable given the impact of subsidized resources have on the auction.

As a result, it would seem very counterintuitive to FERC's original intent to land at an outcome that is meaningfully worse for existing generators.

History tells us that FERC has consistently promoted balanced market reforms that support competitive markets, which by the way, is their first order of priority despite political affiliation.

States can formulate their own energy policy, but they cannot destroy competitive markets in doing so.

Like all of you, we are anxiously awaiting FERC's decision on this issue and remain cautiously optimistic for a constructive outcome.

We continue to believe that Vistra will be in a position to provide relatively robust and stable earnings in the years to come given our strong balance sheet, low-cost integrated operations in the money generating fleet, and market-leading retail operations, which are about to become even more diverse with the closing of the pending Crius acquisition.

On that note, I will turn the call over to Jim Burke to talk a bit more about the Crius transaction.

Thank you, Curt.

Turning to Slide 11.

As you can see from the high-level bullets on the slide, we're very excited about the strategic fit of the Crius portfolio with Vistra's existing retail and generation platform.

Importantly, as Curt mentioned at the beginning of the call, we believe the economics of this transaction are very attractive, exceeding our internal investment threshold and valued at approximately -- at 4x enterprise value to EBITDA multiple pro forma for the full run rate of forecasted synergies.

In fact, as a national integrated power company with generation and retail assets in multiple states, Vistra is uniquely positioned to create value with the Crius platform.

We project we'll be able to achieve approximately $15 million in annual EBITDA synergies and approximately $12 million in additional annual free cash flow synergies following the closing of the transaction.

The acquisition will also accelerate Vistra's previously announced organic growth strategy, enabling us to forgo approximately $29 million of expenditures through 2023 from this effort.

Financial benefits aside, we are particularly excited about this transaction as a result of the quality of the portfolio we will be acquiring.

The Crius portfolio has recognized, established brands, market-leading attrition rates and a demonstrated track record of successful customer acquisition through multiple sales channels.

The portfolio complements Vistra's long generation position in the Midwest and Northeast markets, and as just mentioned, will accelerate organic growth strategy in these regions.

In addition, the composition of the portfolio as largely residential and small business, should command a higher multiple due to the inherently higher margins in these segments.

Let's dive a bit deeper into some of these points on the next slide.

Crius with its approximately 1 million residential customer equivalents has demonstrated success with its high growth, high margin retail strategy.

Focusing on higher-value residential and small business customers, Crius has an impressive track record of new customer gains through various sales channels across multiple brands, and its attrition rates are the lowest among peers in the markets where it operates.

Crius has been successful in its customer acquisition and retention efforts as a result of leveraging its diverse sales channels and exclusive partnership strategies.

These partnership strategies are primarily executed through its Energy Rewards Platform where Crius partners with established providers to cross-sell its retail electricity offerings.

These integrated energy platform offerings will expand Vistra's existing sales and marketing channels, enhancing its strategic fit with our organization.

Following the acquisition, Vistra will have a retail presence in 19 states and the District of Columbia, with dual energy market offerings in many states.

As you can see on Slide 13, Vistra will now have a retail gas product portfolio in 13 states, which we believe will be a great addition to our existing operations.

Retail gas tends to have similar margins as electricity, but gas customers tend to be a bit stickier as bill size is often meaningfully lower in this segment due to lower overall volumes.

Being able to sell a customer 2 services, electricity and gas, leverages the cost of acquisition by adding incremental margin to the customer relationship.

In addition, retail gas is a naturally synergistic business for Vistra, as we are already one of the largest purchasers of natural gas in the country.

To give you a bit of background on how the retail gas business works, the local utilities are responsible for ensuring that natural gas can be delivered to residents in their service territories.

As a result, the local utilities contract for the necessary gas pipeline and transport capacity, as well as for local gas storage and allocate the applicable transportation and storage assets to entities providing the retail gas product to the end users.

Vistra, therefore, will only be responsible for procuring and delivering the actual commodity, which is very easy for us to do in an affordable manner because we already are a bulk purchaser of natural gas necessary for the operation of our gas plants.

In short, though the retail gas portfolio is only approximately 15% of the Crius retail business by volume, we find it to be a nice strategic fit for our organization and we are excited to meaningfully expand our retail gas operations at the transaction close.

Finally, one of the greatest benefits of the Crius transaction is the incremental retail load Vistra will be acquiring which meaningfully improves our expected generation to load match.

Including the default service load Vistra has contracted, we forecast we will be nearly 50% matched in 2019, with approximately 90% of that forecast load being sold through our preferred retail channel.

As we depict on the right-hand side of Slide 14, our commercial team can sell Vistra's long generation through 3 primary channels: directly to one of our retail subsidiaries, to utilities and default service auctions, or directly to third-parties in the wholesale markets.

Of these channels, we prefer selling our length directly to our own retail subsidiaries as we are able to eliminate transaction cost leakage on the bid-ask spread and reduce the total cost of collateral postings.

The other sales channels are effective but marginally less attractive, with sales through default service auctions and third-party sales in the wholesale markets being the next most attractive channels in that order.

The incremental load we will be acquiring with the Crius acquisition is primarily located in the Midwest and Northeast markets, which is exactly where we are planning to focus our organic growth efforts, giving us established brands, sales channels and infrastructure as a platform for this organic growth.

Over the last several weeks, the Vistra management team has been working diligently with Crius to ensure a smooth transition.

As our teams have continued to interface and share best practices, we're even more excited about this transaction.

The Crius and Vistra teams emphasize a high performance culture with a primary focus on the customer.

I have no doubt the Crius operations are the right fit for our organization, and I look forward to announcing a closing of the deal hopefully in the second quarter.

I am hopeful we can quickly close the transaction to avoid any further disruption that has the potential to erode the value of the business.

I will now turn the call over to Bill Holden to cover fourth quarter and full year financial results.

Thank you, Jim.

Turning now to Slide 16.

As Curt mentioned, Vistra concluded 2018 delivering $2.809 billion of adjusted EBITDA from our ongoing operations.

These results reflect a full year of operations from legacy Vistra and results from the legacy Dynegy operations for the period from April 9, 2018, through December 31, 2018.

Including the negative $18 million net impact of the partial buybacks of the Odessa power plant earnout that we executed in February and May, Vistra's adjusted EBITDA from its ongoing operations would have been $2.791 billion for the year.

Vistra's strong results, coming in above consensus and just above the midpoint of management guidance, were directly attributable to robust cost management across all markets, offsetting a relatively mild August in ERCOT.

Retail also exceeded management expectations for the year, driven by residential customer account growth and margin and cost management.

For the full year, CAISO exceeded expectations due to favorable prices, higher generation volumes and lower SG&A expenses, while PJM was also favorable as a result of the NEPCO plant retirement and subsequent move to the Asset Closure segment.

Vistra's 2018 adjusted free cash flow before growth from its ongoing operations was $1.611 billion, which, as Curt mentioned, is $61 million above the high end of management's prior guidance range.

The favorable results are primarily attributable to CapEx spend discipline during the year.

Including the negative $22 million net impact of the partial buybacks of the Odessa power plant earnout, Vistra's 2018 adjusted free cash flow before growth from its ongoing operations would have been $1.589 billion.

For the fourth quarter of 2018, Vistra's adjusted EBITDA from its ongoing operations was $719 million or $721 million including the positive $2 million net impact of the partial buybacks of the Odessa power plant earnout.

Full segment results for the quarter can be found on Slide 22 in the appendix.

As Curt mentioned, today we're also reaffirming our 2019 guidance ranges, and we still believe 2020 adjusted EBITDA from ongoing operations is tracking relatively flat to 2019.

Our confidence in our 2019 guidance ranges and the improvement in our 2020 outlook is due in large part to the incremental hedges we have added for those years.

As you can see on Slides 17 and 18, as of December 31, 2018, we were largely hedged for 2019 in our core markets of ERCOT, PJM and ISO New England.

And as of last week, we are nearly fully hedged in these markets for the year.

Similarly, as of December 31, 2018, we were largely hedged for natural gas in ERCOT in 2020 and we improved our ERCOT heat rate position to 42% from 28% at September 30.

Also in the fourth quarter of 2018, we improved our New York-New England and PJM hedged percentages by 8% and 32%, respectively.

As our commercial strategy is to take advantage of the volatility in forward curves to hedge at prices that are at or above our fundamental point of view, we have improved the 2020 hedged percentages even further in the first 2 months of 2019 to 48% for ERCOT heat rate and to 32% and 66% for New York-New England and PJM, respectively.

We expect our hedging activities to further lock-in a stable EBITDA profile for the business in the out years.

Finally, let's turn to Slide 19 for a brief capital structure update.

As you can see in the table, Vistra had approximately $11.1 billion of long-term debt outstanding as of December 31, 2018, reflecting debt reduction as a result of approximately $120 million of open market repurchases of senior notes in the fourth quarter.

In February of this year, we completed a bond issue and senior notes tender offer and redemption that reduced our annual interest expense by $20 million on a pretax basis.

We will continue to look for opportunities to optimize our balance sheet and reduce our total debt as we work toward achieving our long-term leverage target of 2.5x net debt-to-EBITDA by year-end 2020.

And as Curt mentioned, we have now executed approximately half of our aggregate authorized $1.75 billion share repurchase program, leaving approximately $813 million available as of February 15, 2019.

Following our share repurchases, Vistra had 486 million shares outstanding as of the same date.

Despite our stock price recently achieving a new 52-week high, we continue to view our stock price as undervalued.

As a result, we expect we will continue to allocate capital towards opportunistic share repurchases under our existing program, as previously announced.

Our diverse capital allocation program is in full swing as we initiated our dividend program this month, continue to repurchase shares under our authorized share repurchase program, delever and execute on tuck-in growth opportunities, including the Moss Landing battery storage project and the Crius acquisition.

All of this is possible because of the relatively stable EBITDA and meaningful free cash flow generated by our integrated operations.

We will continue to focus on execution and delivering on our commitments in 2019, all in an effort to create value for our investors.

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

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

Sorry, I did hop on the call just a tad late, so if I'm asking you a question you already answered, my apologies.

When you talk about the upside that you think you see in ERCOT from the change in the ORDC rules, how much of that do you think is already priced into the curves?

And how much of that do you think is -- needs to be sort of validated by volatility that we might see this summer that would cause the curves to move to where you think intrinsic value is?

Yes.

So this is maybe more than you're bargaining for but I think it's worth just talking about how the curves have moved, Greg, because back after the summer we came out, there was a lot of chatter about needing to improve the ORDC or some other reform, as you may recall.

And then there was chatter out there that it may be a one standard deviation move, no discussion about whether it will be a single curve or the 24 curve.

But we were pretty certain at that point in time, some amount of that was factored into the curve.

I think people felt like there was a high probability that something would get done.

We took some advantage of that, in particular a little bit in 2020, but a little bit also, we had some '19 still open, we took advantage of it.

And then if you remember, there was 2 or 3 times that the PUCT sort of put it up on the schedule and then delayed it.

I think the curves, kind of, drifted off a little bit because there was some uncertainty around it.

And of course, we finally got it through.

And then there was a response, a pretty positive response after that.

And the reason I tell you all that is that I think it has ebbed and flowed.

And then recently and this is not -- this is pretty typical.

It's kind of -- the curves have, kind of, drifted off a little bit.

And it happens sort of this time of the year.

I fully expect that as we get closer to the summer, we see our first hot day and people start to see how the market is going to react, that we'll probably see another move up in power prices for '19.

And then typically, when you get into '19 summer, if you see a hot summer, you'll see 2020 move up.

But as it happened this year, we didn't really have, in August, the summer we thought we would.

But we still saw a move-up in '19 because as we rolled out, liquidity went from '19 into '20.

So that's a factor.

But also people realized that reserve margins were actually going to -- actually go down, not up.

I think we'll see that same thing happen in '20.

So that's a long way of saying that it's hard to really know for sure, and I'm not trying to avoid the question, it's just very hard to know.

But I would say, right now, there's room to move in both the '19 and the '20 curves for summer of '19 and '20, respectively, just at where the curves are today.

That's partly just due to just how the market tends to move.

But it's also, I think, the market has not fully realized the impact of the ORDC.

And I think one thing that is probably still being digested, because this is all kind of esoteric stuff, at the end of the day it is in this whole single curve versus multiple curves.

And basically, it really comes down to this loss of load probability and the mean of the loss of load probability and if it's on a single curve versus multiple curves.

The standard deviation around that mean is actually higher, which means the effect of the 0.2 and the 0.5 is actually higher than it would've been if it was under multiple curves.

I'm not sure the market has digested it, because I don't know that they really know how that's all going to play out.

So I think this may be a little bit of wait and see, too, that we're going to need to see how the market reacts.

I think if the market is a little bit warm and we start to see scarcity and the ORDC comes into play, I think you could really see '20 and '21 off to the races.

So I think some of this is going to be driven a little bit by how weather turns out.

But we do believe there's still some upside around the ORDC, given where the curves are currently.

Great.

And then, Bill, could you reiterate where you said you are in terms of how much you've hedged for '20 in ERCOT?

And I presume you used those intermittent runups as opportunities.

But also can you -- I think you guys do, when you talk about hedging, that's net of a significant amount of megawatts that you hold back and take to spot during the summer to sort of self-hedge.

So can you just talk about that as well, so we can understand how much exposure you have if the curves do move in your favor?

Yes.

So the hedging that we've done through -- for 2020 since the end of the year will take us up to 48% hedged against ERCOT heat rate.

And that's in what year, Bill?

And that's for 2020.

Year 2020.

Okay.

So you're -- and -- but that's so you're 52% open, but aren't you -- do I need to sort of take into account the fact that you're holding back the like 1,200 megawatts?

Or does that take it into account in that hedge percentage?

Steve Muscato here.

So go ahead.

Yes, this is Steve Muscato.

The way I think about it is, yes, we do hold back some generation for basically potential outages or weather changes that make our load move up pretty rapidly with temperature.

The way to think about it is, it gives us the opportunity to capture any deviations between the day ahead and the real time, because if the day ahead clears at a particular level, we could typically cover our load changes in the day ahead, which then gives us a lot of that open generation for changes in the real time market.

So that's something that we ought to...

But can we just -- Greg's just asking a simple question.

In our hedge percentage, does it include the 1250 in it?

So that open position or not?

And I think it does.

It does.

So Greg's just asking, is that against that, because you know you've got this holdback?

And it does include it.

Correct.

Okay.

That's clear, guys.

And, Greg, one other thing just to tell you, we've sort of purposely held some open here in '20 because I think you've got -- you probably picked that up from what I was saying, is that we think there's room to move, and pretty significant room to move in '20.

We don't see -- it's hard to see that much newbuild coming on and -- in between now and '20.

So -- and we also don't think that the market has fully absorbed the ORDC effect.

So we do think there's some movement.

And so that we have -- we're, kind of sitting a little bit on '20.

You'll -- if the curves move, you should expect us -- and they move up, you should expect us probably to take some more off.

If they don't, then we're going to be patient.

Great.

One more quick question for you, and it might be a curve ball, because I don't know, you probably didn't see it, but NRG in their release this morning talked about how they are reducing their net debt-to-EBITDA target to between 2.5 and 2.75.

So they're coming down to sort of where you guys already are in terms of your net debt-to-EBITDA aspirations, and they're explicitly targeting, eventually getting to an investment-grade credit rating.

So can you just reiterate because it seems like in terms of -- people have been pushing you in the past to sort of, why don't you go towards NRG and go to 3x and buy back more stock?

But now it seems like NRG's figured out that they need to come in your direction.

So can you just reiterate what your aspirations are in terms of capital allocation, credit metrics?

And do you aspire also to ultimately get to IG?

Yes.

So look, the first thing I'd say is imitation is the sincerest form of flattery.

So -- but more importantly and to the point, we've been pretty steadfast.

And we did move -- and you know this, we did move getting to 2.5x out a year because we felt like just where our stock was trading that it made sense to reallocate capital in 2019.

And so we did do that.

But we are absolutely committed to get 2.5x.

And we believe, I think it's going to take time, and I think the first step is actually to get an upgrade from where we are today, I think we -- that's squarely in our sights.

And I think if we execute it, that will happen and that will then lead us to the position where we can get investment-grade.

We do want to get to investment-grade.

The credit spreads at least today probably don't say that, that's something that's a big deal.

But it's not about that.

I think it would be good for the equity.

And it also would open up opportunities on our commercial and industrial retail business where, at times, we have to sleeve or we may not even get to see the business.

So there's a business proposition in here.

And I think this -- the reason -- one of the reasons I believe we have such a high free cash flow yield is the risk premium in our business.

I think that has been driven in the past over time because we carried too much leverage, and there was the risk of financial distress in these stocks.

And I think we want to put that completely in our rearview mirror.

And I think 2.5x is the right place to get, to have that discussion with the agencies.

And then we'll see what we do from there.

But we feel like given the metrics at that -- at 2.5x and just the absolute level of debt, it feels to us like that's the right place to be in order to have a serious discussion about investment-grade.

All right.

And then that drives a lower free cash flow yield and a higher share price.

So that's sort of the magic potion of -- I got that, yes...

Yes, exactly right.

You've got it.

Your next question comes from the line of Abe Azar with Deutsche Bank.

Any thoughts on timing of refinancing the rest of the high cost legacy Dynegy debt?

Or any key dates to focus on where some of that debt becomes callable?

Yes.

Abe, so I think in terms of just refinancing, the 2 new bond issues that we did have covered most of the amounts that we would need to refinance with new money at lower cost.

So the remaining amount of the debt reduction, or those -- the lion's share of it, will be done with redemptions from cash.

I think you can look at when the redemption premium stepped down, I think a large number -- some of those were in November each year, we would do the math when we -- when we're planning, getting close to the redemption dates about whether it makes sense to do it earlier or wait until the stepdown in the redemption premium.

But I think we've laid out in the cap table at the end of the presentation that we're planning to do about $800 million of that this year and then the balance of -- to get to the 2.5x we would do in 2020.

Got it.

And then can you provide an update on the status of the Moss Landing battery?

When was spending supposed to ramp up and is there something you're waiting for before putting capital to work there?

Yes.

So a good question.

As you know, that's a bit of a fluid situation.

And with NextEra, sort of throw in the -- it seems in our -- in bankruptcies in our sector and there is an obligatory federal versus state fight that always seems to go on, FERC versus the states.

That's, kind of, slowed some things down, and has created, what I'd say, just a little more hair on how PG&E wants to proceed.

But what I can say, Abe, because we're in constant contact with these guys, is number one, the state wanted this project; number two, the CPUC approved it; number three, it doesn't suffer from what others have, which is it's not wildly out of the money.

In fact, it was by far the lowest cost deal because of the Moss Landing site.

So there is no mark-to-market gain by rejecting the contract.

And so what we're hearing from PG&E is it's full steam ahead.

What the real question is, is when are they going to assume these types of contracts?

And they're a little concerned, I believe, in how they're going to handle that given this jurisdictional issue with FERC and the battle that's going on there.

So we're moving forward and we have talked to them, they want to move forward in the contract.

We still have a valid contract.

It's not been rejected.

The question is, is when will it be assumed?

And we're hopeful that's sooner rather than later.

I think what we have to remember is that we do have a contractual commitment here.

And then we have to weigh the odds of whether it would ever be rejected.

And at this point in time, we feel like it's an extremely low probability that it would be rejected given the discussions that we've had directly with PG&E.

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

So, just following up on Moss Landing.

It doesn't sound like the decision to reject or resume is going to be taken anytime soon because they probably have to figure out what the exit looks like.

It could take time, let's just put it that way.

So, if it does take time, is the assumption that you would continue on the current course, assuming that it will at some point get resumed?

Or do you have to hold and wait for the decision, which would slow down the entire process?

Yes, so I -- look, because we're in active discussion with PG&E, I don't feel like it would be fair for me to have that discussion.

But I think your observations are correct.

That's what I was trying to convey, and I'll be just very direct about it.

The assumption of contracts could be pushed out, and we have a contract right now.

The only thing that would change that is if it was rejected.

I think the likelihood of that is very, very low.

And so we'll work with our board and we'll work with PG&E when we get to the point, which is going to be in the April to May -- late April sort of May time frame, where we would have to actually sign the big contract for the equipment, and we'll make our decision then what we have to do.

There is a number of different things we could do either in front of the bankruptcy court or working with PG&E in order to make sure that we move forward.

We're committed to the project.

I just -- I can't tell you right now what that ultimate decision will be if we have to then make a decision come May to sign an EPC contract or equipment contract.

And we'll have to see what that is, and I'm going to do it with the consultation with our -- we have bankruptcy attorneys on board because we have to understand the process.

And so we'll have to consult with them.

And then ultimately, I'll have to go to the board.

But most importantly, I think it's the active dialogue that we have with PG&E and working with them on certain things that will give us the comfort that we're going to continue on with this project and have no issues or no risk of rejection.

All that is still playing out.

But we intend and we're moving forward with the intent of completing that project.

Understood.

And then maybe on Slide 28.

You have these realized estimated power prices, and there seems to be now for ERCOT, a $6 forecasted premium that you've, kind of, estimated for 2020.

I know this number has moved around quite a bit.

Could you just give us some perspective on what that $6 now reflects?

And there's obviously something for ISO New England as well.

So some color on the confidence around that number would be helpful.

Yes.

So it's -- yes, you -- I just want to make sure because this is -- it's even been confusing for me, by the way.

We always struggle with what's the best way to show you guys this kind of information.

So part of this -- part of that number is what I'd call sort of realized -- actual realized premium relative to where the market came in.

And then as it relates now, most of it in 2020, obviously all of it, is really projected.

There is a significant amount of auction value or extrinsic value that is in the market, and we model what that value is relative -- and you lose that volume -- value.

That value decays over time.

And then ultimately, as you go from real time -- I mean, from day ahead to real time, you don't have that anymore.

You don't have that flexibility.

Part of it is the value of being able to back down units in times and optimize by buying from the market.

There's a number of different options that you can go after that we have historically proven that we're able to do.

It's also our ability to hedge at the -- at the periods of time where there is just higher pricing than where spot prices come in.

And that's why it's so important as a company that we have a point of view, and that we hedge when prices are at or above that point of view, and have a very good modeling capability so that we feel comfortable that we are hedging at prices above spot.

And we've also had a very good track record of being able to do that.

So it's a combination of things.

I don't know -- Steve Muscato's here with me.

Steve, is there anything you would add to that?

Yes.

It's basically -- I mean, I think, Curt, you captured it.

It's the ability to, in essence, capture different points along the forward curve that we call extrinsic value, selling into strength or anytime the price moves up.

And also as we take the portfolio into the day ahead and real time markets, being able to optimize around whatever price signals we're given.

And so it's a combination of existing hedges we have on and the combination of hedges we hope to put on in the future.

And you know what, probably you're -- it's a good observation though, that value does move around, because it's influenced by the volatility in the market and we pull it from forward volatility.

And so as the market changes.

Now we have our own fundamental view around volatility too which factors into when we hedge.

Correct.

So it does move around some.

I think we've been -- I think what we've been able to demonstrate, I hope, I believe we have, is that we've been able to capture a lot of that along the way as we hedge.

And so in '19, we've locked a lot of that volatility in.

The reality of the situation is, in an increasing price environment, that premium will shrink, as you would expect, because we're managing risk as much as we are absolute price.

We're trying to create a stable steady earnings -- and steady earnings stream and we're not looking for the highs of the highs.

So you may see that, that premium will shrink.

But once the market plateaus out and it hits the sort of highs of the market, then it's much easier then to create that premium.

And then in the years past when prices were actually declining, then that, we were able to hedge ahead of some of the declines because, again, our fundamental view showed that the market was actually on a decline and we went out as fast as we could and tried to hedge as much as we could in the forward market.

And then that actually proved out to work out for us in a big way.

So that's, kind of, how we think about it, approaching it.

Yes, and I think you asked about New England, as an example.

We've all seen a material drop off in gas volatility in New England.

And so that's really the component that's impacting the New England pricing.

Going into the winter, there was a lot of discussion on what's going to happen in Algonquin.

And obviously, Algonquin volatility wasn't necessarily -- it didn't materialize and that's reflected also in the forward market at this point in time.

Got you.

That's super helpful.

And clearly, your track record helps confirm or at least get comfort around those numbers.

I guess, just one final thing, around the shareholder base.

It was very helpful to hear the change in shareholder base.

Given you have dry powder right now to buy back more shares, is there any expectation of any, kind of, block deal or any broader deal with some of these shareholders who are looking to exit?

Are they still looking to exit?

Any color or perspective on that?

So look, I think we -- I think the big thing is, and you guys probably saw this, I mean when that 13 asset that came out.

We've seen a dramatic change in our shareholder base, obviously, since we came out of bankruptcy but even recently.

We've got 2 of the largest shareholders we had, number two and number 3 shareholders that are now down to 6%.

And I think one of them is probably below that at this point in time.

And then we've got Vanguard and Fidelity, who have now come up to number two and number 3. And then when we look at our shareholder base, and I -- and we couldn't say this coming out of bankruptcy, I think it was about -- what, Molly, 16 I think, out of the 20 now or -- or 15, sorry.

15 out of the 20 are what we would consider long-term investors.

People who are coming in because they desire to own the stock in the long run, they believe in the strategy and they like the price point they're able to get in on.

And the other thing I like about it is, is many of those folks came in at lower levels and have actually increased in a significant way their holdings.

Now we're not done, and this is why we're going to be in Boston and New York next week.

We're going to Europe.

We wouldn't even have been able to go to Europe had we not had a dividend.

So that opened up doors in Europe.

We're going to go over there and hopefully get people interested, long investors.

You guys know this that -- and we went up to Canada.

Canada are more long-oriented investors.

And we're hitting about as, every long-oriented investor that we can hit.

And I'm doing it personally because I think it's important to hear the story directly from us.

It's the only way in my mind that you get this rotation, and you get it without having your stock price suffer because you've got to create demand for the stock.

We can do buybacks, we can do all those things.

But at the end of the day, we've got to create demand, and the only way we create demand is to get out and tell the story.

And I think we've had really good success on that, and I'm willing to do whatever it takes.

And I know Bill is as well, and Molly.

We'll get out on the road if we have to and we'll talk to anybody that is interested in our stock.

I think it's the only way we know how to do it.

Your next question comes from the line of Angie Storozynski from Macquarie.

So 2 questions.

The $813 million left for buybacks, is there any time line attached to it?

Is it through the end of '19?

So, it's -- well this will depend, right, on just where our stock price is.

But it's probably -- it could.

It could leak into the first quarter of 2020, just -- and this is all dependent, Angie, and I'm not trying to avoid the question, it just depends on where our price is.

Because as you probably know, we have different volumes of buyback at different price points.

And so as you might expect, our stock's moved up some, and so we're buying less at that point in time.

But I think our projection is it could leak over a little bit into the first quarter of 2020.

Yes, that's right.

And Angie, that's consistent with what we said last quarter where we said we thought the program will be completed either Q4 of this year or likely Q1 of next year, somewhere in that time frame, depending on where the stock's trading.

Okay.

Number two is, back in December, when we met, you guys talked about 2020 EBITDA being above 2019.

I know that there's upside -- potential upside to ERCOT power curves.

But as they look right now, do you still think that 2020 would be above midpoint of your current '19 guidance?

Yes.

So let me -- good question.

I want to be clear about this.

So we're -- I'm going to talk about this, not including Crius.

So, but we see sort of flattish over -- now over '19 and '20.

And you know this, I think, Angie.

But for us, that's a big deal, because Dynegy had a huge cliff because of the PJM capacity clear, and we've been able to bridge that gap and create a more stable earnings profile.

That's driven by our value levers from the Dynegy merger, to some extent.

It's driven by curves and our ability to hedge some of that.

So we -- and that's where we are today.

I would say that depending on where the curves come in, you heard that long-winded answer I gave to Greg.

But I do think there could be some upside in the curves.

I think that is more of a '20 upside.

And so we could see some of that in '20.

At this point in time though, where we are, is we think that we're sort of flattish.

Because part of that, when we marked that -- when we didn't -- gave you that comment and we had marked that particular plan, it was including some of the uplift that had already occurred from the ORDC.

So part of what's getting us to that flattish nature is the higher curves, and part of that I believe is some of the expectation of the ORDC.

But there could be some upside.

I -- but we're going to wait, obviously, through '19 when we see the '20 curves move more significantly to leak that out, and of course, we'll wait all the way until October, November time frame before we give guidance on '20.

Okay.

And my last question, just a quick one.

I know we talked -- you talked about the battery project with PG&E.

But how do you think about the fact that the project returns, most likely you were planning to add some project level debt.

I would assume that the cost of that debt is now going to go up given that the offtaker's credit has plunged.

So I mean, do you still think it's an attractive return taking that into account?

Yes.

So first of all, we're not going to do project level debt.

We've made the decision not to project level finance it.

I mean I've been in this industry too long, and I remember when everybody was doing project level debts and it got confusing.

And we don't want a capital structure that's confusing.

And we like the returns.

I think we said this when we came out, these are on an unlevered basis, these are returns that are in the mid-teens.

That's very attractive to us.

And so it'll be on balance sheet.

We still believe in those returns.

I think it's important to know that the absolute -- so we do benefit from the price -- or excuse me, from revenues from power.

So we get a resource adequacy payment as part.

And then we also can then optimize using the battery in the energy market.

The key on that is it's not about absolute power price, it's about the volatility in power price and our ability when prices in the day are low because there's all this solar generation, and other generation.

And then you -- and then the solar generation comes off, because the sun's going down and it goes down, and then prices go up.

It's that arbitrage that occurs in there that we get.

So prices theoretically could be 0 during the day and then $10 or $20 during the night, and that's where we capture that value.

So we feel very comfortable about the value and the returns on this.

And so nothing's changed in our mind in terms of the value of this.

And in fact, we know that California needs more of this type of investment, which actually is an opportunity for us as well.

But that just gives you a sense of just what the demand is.

And if there is a higher demand for battery, that means that pricing, when you go from the heavy solar period to where the sun goes down, that means that pricing is going to be high until they get all that new capacity on.

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

Can you hear me?

Yes, Julien.

So a couple of quick ones.

I'll make it snappy here.

So firstly, just going back to the hedges.

Just wanted to understand the change in New England, the price just on the '19, just wanted to understand a little bit more detail on that.

And then also the expected gen moved around a good bit.

I get that power curves move and that shifts things around.

Anything to mention, given that it was around -- it was across all the regions but ERCOT, especially the Northeast?

So on the -- I think on New England, a lot of what you saw there was really the -- what Steve was describing earlier, the extrinsic value has come down because of lower volatilities.

And so that's just had the effect of reducing the realized price without having a corresponding benefit from hedges because the extrinsic value is not fully hedged.

I'm looking at Steve on the -- whether there's anything of note in the volumes.

What we're seeing in volumes is as we do -- as we continue to go through our operational improvements, we are seeing some changes in how the fleet runs at night.

Whether they're start-based or run-based or hours-based machines, and so that's causing some volume changes that you'll see.

It's not having material gross margin impacts at this point, because it's really just whether they run through the night or cycle on and off.

And one thing I'll add to New England, it's really associated with, if you look at Algonquin pricing, it was pretty contained this winter compared to what you've seen historically during cold snaps like if you look at 2014 as an example.

And that decline in volatility is participating through the market.

And the big reason for it was there was some LNG tankers brought in at the Gateway terminal outside of Boston.

So it's something that we have to monitor from year to year how LNG impacts that market and perceptions on how it's going to impact that market.

And the only thing I'd just add on to what Steve's said is some of those price increases were in off-peak hours, which has affected the dispatch.

And to the extent we dispatch more in the off-peak, it lowers the average realized price, because we run that -- we're earning margin but we're running more at lower priced hours.

Got it.

All right.

Excellent.

And then lastly, just real quickly on the Illinois situation.

Obviously, somewhat dynamic and fluid here given the NPS and the prospects of legislation and your own process on examining the portfolio.

Can you give us a little bit of a, more of a sense on time line?

And then what the potential combinations here are?

I suppose legislation is probably at some point during the session this year?

NPS is at some point this year?

But just help us understand the theory -- your decision-tree, if you will.

Yes.

So good question.

I think you guys know that there is a new administration in Illinois, Governor Pritzker.

He has a fairly aggressive green agenda for the state.

They signed on to the Paris Accord, he made a big announcement on that.

And the governor has asked us, at least that's our understanding, through the Illinois EPA, to have further discussions with the EPA about the multipollutant standard that the Illinois Pollution Control Board had sent forward for hearing.

We agreed to that.

I think whenever a governor asks you to do something for the state, you typically do it.

And it has not slowed anything down yet.

And we've set that -- we gave them 45 days, that's March 15 coming up.

I think the discussions have been very good.

And so we are working toward what we hope is, and I feel, I'd say, cautiously optimistic, a compromise with everybody involved, including the environmental groups and the AG's office, on something that will allow us to move forward.

So I would tell you that we are still on the time line that we would be making decisions around our portfolio in sort of the midyear time frame.

And I think things will become, in some ways, could even become clearer to people what we're doing even sooner than that.

But I think action would probably be taken more in the middle of the year.

I've been very open about the fact that we've got an older and aging fleet there and the capacity market design is horrid.

And it's just not a very good market, and we got challenged assets.

And so we're trying to build something where we can have a sustainable business.

And I think part of that is making some hard decisions like we did in Texas to retire plants.

We'll see about that.

But that's on the horizon for 2019, and I've been very clear with everybody involved in Illinois that this company is going to take action one way or another because we're not going to continue to bleed cash and bleed EBITDA.

We're going to clean up this portfolio and we're going to move on with our business.

It takes a tremendous amount of our time relative to the EBITDA that it provides to the company.

And that can't -- that's not sustainable, and it won't be.

So that's about what I can say at this point in time on that, Julien.

This concludes our question-and-answer session.

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

So once again, thank you for your time this morning and we appreciate you being on our call.

And we look forward to the next time we have the opportunity to talk about our company.

So thank you.

This concludes today's conference call.

Thank you for your participation.

You may now disconnect.