Vistra Corp (VST) 2017 Q2 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the Vistra Energy Second Quarter 2017 Webcast and Conference Call.

(Operator Instructions) Thank you.

Molly Sorg, Vice President, Investor Relations, please go ahead.

Thank you, Emily, and good morning, everyone.

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

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

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

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

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

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

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

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

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

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

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

We appreciate your interest in Vistra Energy.

I'd like to begin our discussion today on Slide 5 with a brief highlight of our second quarter financial results.

Vistra Energy finished the second quarter with adjusted EBITDA of $345 million and year-to-date adjusted EBITDA of $621 million.

Strong performance in what proved to be a challenging quarter, driven by a mild start to the Texas summer and the beginning of an unplanned outage at Comanche Peak's Unit 2 that I know many folks have been waiting for us to talk about, which I will do right now.

The Comanche Peak outage began when our plant operators observed increasing temperatures inside the Unit 2 steam turbine generator.

That's a Siemens-manufactured generator.

I want to be very clear that our steam turbine generator, as many of you probably know, is a standard power generation equipment and is wholly unrelated to the nuclear power reactor side of the plant.

There were no -- any ancillary effect at all.

In fact, we were able to bring the unit down and the generator down without any issues at all.

The unit was brought into an unplanned outage on June 5 to investigate the rising temperatures further.

Our operations team determined the primary damage was to the unit's stator, which is the stationary component of a generator.

Following extensive evaluation with several experts, including the manufacturer, as I mentioned, Siemens, we determined the stator was repairable.

The team worked for the balance of June and the month of July to repair the damage and perform tests to validate the effectiveness of the repairs.

While the repair was quite detailed and tedious work, I will say that this disassembly and reassembly of the equipment is really what takes a lot of time.

You have to be very precise in putting back together a generator to make sure that everything is ready to run again.

We presently expect the unit will return to service late next week in time to capture part of the important Texas summer season.

We just need to hope that the weather performs well for us in the remainder of the summer, and we all have our fingers crossed on that one.

In total, we expect the full year EBITDA impact from the outage to be approximately $75 million, of which approximately $20 million relates to the incremental O&M expenses incurred during the outage and approximately $55 million relates to lost gross margin for the 2-month duration of the outage.

We have filed an insurance claim related to the outage, and we are also evaluating whether we might have any indemnification claims against certain third parties.

At this time, we do expect to recover in full all of our out-of-pocket costs and expenses that are related to repairing the unit and that exceed our $5 million deductible.

It is likely, however, that the receipt of any insurance proceeds will not incur till 2018.

We do not expect any recovery, however, for the impact of the lost gross margin realized for the duration of the outage as our accidental outage insurance policy, which would cover such loss profits, does not kick in until the unit has been out of service for more than 12 weeks.

As we expect the unit to return to service next week, we do not expect to be eligible to make a claim under this policy, which frankly, is a good thing as we would rather have Comanche Peak Unit 2 up and running.

I should also add that our commercial team proactively and successfully took steps to mitigate any potential negative impacts from the outage on our retail operations or on our hedge positions.

As a result, our hedge portfolio and retail operations were effectively insulated from any negative impacts related to the outage.

I would be remiss not to acknowledge that the timing of the outage leading right into this Texas summer was disappointing, and especially in our first full year coming out of bankruptcy.

However, our team has worked tirelessly to return the unit to service as quickly as possible while carefully observing all safety and quality control protocols, and we do expect the unit to return to full load in time to benefit for more than half of the fourth and third quarter of ERCOT demand.

Last, I think it's important to reinforce that we believe this outage was a result of an incident isolated to Unit 2. Nevertheless, we intend to take additional steps to give us the ability to install a replacement generator in the future should a similar event occur.

We have a spare rotor on site at Comanche Peak, and it is likely we will have a spare stator manufactured.

We believe this is prudent given the importance of Comanche Peak to our overall operations.

Moreover, even though we presently estimate the full year impact of Comanche Peak Unit 2 outage will be approximately $75 million, we remain confident in our full year adjusted EBITDA guidance range, both because we were tracking towards the higher end of our adjusted EBITDA guidance range following the first quarter and also as a result of known offsets, which Bill and I will discuss later on the call.

As a result, we are reaffirming our full year guidance ranges for 2017.

Moving on to capital allocation.

I'm excited to announce that we did close on the acquisition of the approximately 1 gigawatt Odessa plant on October 1. Thanks to quick efforts of our integrated team working on the transition and integration, this asset is now part of our portfolio as we enter the month of August in Texas, which is great timing for our generation business and a helpful offset in 2017 to the negative impact of the Comanche Peak Unit 2 outage.

The addition of this flexible gas-fired generation asset to our portfolio is an important example of our commitment to opportunistically acquire high-quality, gas-fired assets in ERCOT.

We believe the Odessa plant will be a valuable addition to our generation fleet, in part given its ideal location to capture the current natural gas price advantage in the Permian Basin, which Sara Graziano, our Senior Vice President of Corporate Development, will describe further in a few minutes.

Sara's team also led the acquisition of the 180-megawatt Upton 2 solar development project, which remains on schedule to be online for the summer of 2018.

As we have previously mentioned, the Upton 2 project is a great addition to our fleet and is instrumental in our future retail product offerings.

Going forward, we remain opportunistic on both the potential to acquire additional gas-fired generation assets in ERCOT, to do further renewable projects and on any potential ex ERCOT growth.

As we have stated previously, we do not feel compelled to diversify outside of ERCOT to mitigate weather or market risk given the strength of our integrated portfolio.

We have commented on a number of occasions that any large-scale M&A transaction diversified outside of ERCOT would have to stand up to a number of company's self-imposed criteria, such as customary control premiums, relative ownership sharing of synergies and economic resilience under numerous market scenarios.

I will say, though, that there are economies of scale in this sector, and they are important and things that we look at in trying to drive down cost in our business.

We remain disciplined with our capital allocation approach, and this discipline applies to maintaining the health of our balance sheet, which we believe is a key attribute for sustainable success in this business.

Vistra, we believe, is in an enviable position in today's market.

We've done our dirty work.

We've cut -- our cost rationalization is complete, and we have a very strong balance sheet with industry-leading conversion of EBITDA to free cash flow.

We intend to remain vigilant with respect to capital allocation, seeking meaningful returns for our shareholders as we make future investment decisions and to maintain a leadership role in the industry.

To the extent we do not find investment opportunities in the market that we believe will create value for our shareholders, we could return capital to our shareholders in the form of potential share buybacks or potential dividends.

Regarding share repurchases, we recently received what we believe to be a favorable ruling from the IRS, paving the way for potential share buybacks ahead of the 24-month restricted period contemplated in the EFH bankruptcy tax matters agreement.

We are working through the mechanics of how we can execute on such share repurchases should we determine to implement a plan in the future.

So we now believe we have a path forward.

I'm now going to turn to Slide 6. We're providing today an interim update on our operations performance initiative or as we call it, OP.

We have included a Hot Topic section to our presentation today, of which OP will be one of the topics that Jim Burke will cover.

While OP is not yet complete, we are already capturing savings opportunities this year, which are helpful offsets to the negative impact of Comanche Peak Unit 2 outage this summer.

As a result, we thought it would be helpful to provide you with an interim update on the process.

Through the OP process completed in the first part of this year, we have identified approximately $28 million of EBITDA enhancement we expect to achieve in 2017, which would translate to approximately $45 million to $50 million on a full run rate basis.

The EBITDA enhancements we have identified are primarily driven by cost-savings opportunities, efficiencies in field handling and logistics as well as heat rate improvements, as Jim Burke will describe in more detail.

This is a process I have personally led at 4 different companies, and the results are verifiable and create meaningful recurring value.

We plan to report further results of OP on our third quarter earnings call.

Similarly, as we have communicated a number of times previously, any decisions related to the optimization of Luminant's generation fleet will likely to be made in the fourth quarter.

As a final note on OP, we've been working through the process and implementing several ideas.

However, given the nature of these types of improvements, it is prudent to see the results before you count the value and communicate it externally.

By communicating the preliminary results today, we are indicating our high level of confidence in capturing the value described.

Now I'm going to move to Slide 7. Vistra once again realized solid performance from the commercial and operations teams in the second quarter.

Consistent with our fossil fleet first quarter performance, commercial availability was 96% for the quarter.

The importance of high commercial availability from our fossil fleet was highlighted in June with the unplanned outage at Comanche Peak.

Making sure our units are available when market prices reflect attractive economics continues to be a core priority for our operations, and it is critical to our success as an organization.

Similarly, contributions from our opportunistic hedging and asset optimization activities once again delivered meaningful value to the enterprise.

Year-to-date, Luminant's commercial operations team realized prices that were nearly 46% higher than settled prices during the same period.

Also on Slide 7, I would like to highlight a new hedge disclosure we are providing for the first time and will update on a quarterly basis going forward.

The table on the far right side of the slide now provides you with the hedge premiums and generation we expect to achieve for the balance of 2017.

The hedge premium includes all contract revenues for the balance of 2017 our mark-to-market hedge impact as of June 30, 2017, as well as the shape and asset optimization impact we are anticipating over the same time period.

If around-the-clock settled prices for the year come in lower than our -- than current estimates, the value derived from our hedges will be even greater.

As we have said before, so long as we continue to see reasonable levels of volatility in the forward curves, which we currently expect will be the case, we'll continue to have occasion to opportunistically hedge our wholesale win in future periods.

Slide 8 is an example of this volatility.

As is depicted in the graph on the slide, in the last several months, ERCOT summer heat rates have increased materially for the years 2019 through 2021.

Luminant's commercial operations team took advantage of this volatility to hedge some of our volume in the summer periods of what we believe are attractive levels.

While the hedge levels for 2019 through 2021 are modest relative to our total open wholesale position in those years, it is an example of how our commercial team opportunistically takes advantage of liquidity in the market to build a hedge book that year-after-year materially exceeds settled prices.

Our commercial team looks for opportunities afforded them given the multitude of liquid forward curves available to hedge wholesale risk acquired to real-time settle.

We look to hedge our wholesale risk at levels above our guidance and our point of view in the market for any given future point in time.

Using this opportunistic hedging strategy year-after-year, Vistra's commercial team has been able to realize power prices materially in excess of annual settled prices as is depicted on Slide 19 in the appendix to today's presentation.

We believe the second quarter of 2017, despite the disappointing weather and the Comanche Peak Unit 2 outage, provides a clear indication that we are executing on the fundamental key factors for success in our business and delivering shareholder value.

In our view, these factors are strong cost management, especially in our wholesale and support organizations; commercial optimization of our wholesale commodity and retail customer business positions; improved management of our balance sheet and capital allocation.

We believe there is a model for this sector, where companies can sustain a long-term value proposition based on strategy, execution and proper governance, and ultimately attract long-term investors.

We will now discuss Q2 hot topics.

The first one is OP that Jim Burke will take over the mic here.

And then the next one will be Odessa that Sara Graziano will talk about.

Jim?

Thank you, Curt.

As Curt mentioned, late in 2016, we kicked off a process called the operations performance initiative, or OP, to ensure our plants and mines were running as competitively as possible in this challenging market environment.

We had just completed our support cost-reduction efforts in October of '16, so we then turned our attention to our field operations.

As we describe on Slide 10, our focus with this effort was much broader than costs.

We are actively working ideas that could create additional value with revenue or margin as well as cost and capital efficiencies.

The OP process combines external and internal expertise from a diverse set of disciplines, experience base and technological prowess.

The process engages approximately 90% of each site's size and our third-party business partners, and workshops had generate over 5,000 ideas, of which over 1,500 are in some form of further analysis and action.

Each idea was analyzed and evaluated for technical feasibility, economic value, ease of implementation and investment requirements, just to name a few.

A rationalization process occurs, and once we complete a review and are ready to fully implement, we use an open tracking platform with regular reporting of results to ensure accountability and ultimately, success.

Our initial focus was on our 3 largest coal sites in terms of generation and mining activity, that being Martin Lake, Oak Grove and Sandow.

However, our efforts are continuing at other sites, and we expect to have these wrapped up by the end of the third quarter.

To provide some insight into the approximately $28 million of results we expect to capture in 2017, we wanted to break the EBITDA enhancements down to describe the items that are expense reductions, which we will classify as O&M savings, versus the items that enhance gross margin, which relate to generation output and fuel expense.

So far this year, given the activities that are already underway, we anticipate a reduction in 2017 O&M expense of approximately $22 million and improved gross margin of approximately $6 million.

These EBITDA impacts are not full year impacts as ideas were implemented at various times throughout the year.

In fact, largely on the basis of the partial year impact, we would anticipate a full year run rate view of the activities already underway would yield closer to $45 million to $50 million on a recurring basis.

To provide more color, I'd like to just share a few examples of our OP savings opportunities with you so you have a sense for the types of initiatives the teams are implementing.

On the O&M expense reduction side, the utilization of consumables has provided a sizable savings opportunity for us at multiple sites, including Oak Grove, Sandow and Martin Lake.

In light of the effectiveness of our scrubbers, we're able to tune our utilization of activated carbon for mercury control, realizing significant savings while meeting or exceeding environmental compliance targets.

Similarly, by optimizing our scrubbing strategy at Martin Lake, we're able to reduce utilization of excess limestone and at the same time, reduce our auxiliary load by 30,000-megawatt hours, creating more value from the plant output.

When evaluating our maintenance strategy, we conducted a comprehensive review of our preventive maintenance programs to better align it with the current economic and operational environment.

As a result of this review, we're budgeting and tracking our contractor hours more aggressively, adopting a broader utilization of non-original equipment manufacturer parts and benefiting from the best practices of existing contractors to save time and money.

For example, at Sandow, our business partner [Florida], introduced us to a new scaffolding technology and contractor that saves us time and money while streamlining the number of contractors we have performing this function.

On the generation and mining side, we're able to add incremental generation at some of our facilities due to efficiencies from steam cycle improvement through better valve monitoring, repair and in some cases, replacements.

At Oak Grove, replacing items such as leaking turbine drains, main steam line drains and boiler feed pump recirculation valves that help improve plant heat rate by over 100 BTU per kilowatt hour.

Our teams have better focus on ensuring that our units are capturing the energy throughout the steam cycle and generating megawatt hours.

This is assisted by monitoring the thermal couples throughout the steam cycle, both on site and by our performance optimization center in Dallas, which closely monitors our sites.

Finally, our operators have better awareness of heat rate and the tools to manage performance real-time, which has provided additional volume and margin as evidence by our 96% commercial availability performance in the second quarter for our fossil fleet.

In addition, in both Martin Lake and Oak Grove, we've been able to lower our minimum sustained output known as low sustained limit, or LSL, in low price environments while also enabling our units to ramp up more quickly when called upon in response to improving market conditions.

And on the mining side, our team was able to implement a number of techniques to improve productivity.

A key one has been a faster diagnosis and repair for our conveyor belt at Three Oaks mine, which serves Sandow, which will reduce downtime and additional hauling requirements, thereby lowering our overall cost per ton for lignite.

We are already realizing several million dollars in lower hauling expenses in 2017 as compared to 2016.

In summary, these efforts are already underway, with more to come, and it would not be possible without the buy-in and ownership by the entire Luminant team.

We understand that this is how we compete, by continuing to find ways to create value in a dynamic and challenging market.

We look forward to sharing more information about the complete effort on our third quarter earnings call.

With that, I would like to turn it over to Sara Graziano, who led our efforts on our successful Odessa acquisition.

Thank you, Jim.

We wanted to take a few minutes on today's earnings call to provide a little bit more color around our acquisition of the Odessa power plant in West Texas.

As we mentioned in our July 6 press release, the Odessa plant is ideally situated in West Texas to capture the current natural gas price advantage in the Permian Basin.

Oil drilling activity in the Permian Basin has caused a sharp increase in associated gas production, with an increase of approximately 5.8 billion cubic feet per day in 2016 to approximately 6.6 billion as of July 2017 and is projected to further increase to approximately 11.5 Bcf per day in 2020.

This increase in production has overwhelmed available takeaway capacity and created deep discounts in Permian gas pricing in today's market.

Slide 11 depicts the location of the Odessa plant, which has direct access to both the El Paso and OneOk pipelines to which multiple producers are connected.

Very few plants are situated to be able to source gas from deep within the Permian Basin, adding even deeper discount than what is seen at the Waha Hub.

Moreover, Odessa has an option to reconnect to the Enterprise pipeline in the future should market conditions warrant.

Since the announcement of our agreement to acquire the Odessa plant, we have been in discussions with various producers for potential long-term gas supply contracts.

We have seen a great deal of interest from the producers.

And as a result, we believe we will be able to lock in an attractive gas supply for the asset for several years into the future.

While we do believe that, ultimately, additional pipeline takeaway capacity out of the Permian will be built, we intend to take advantage of the dislocations in the market to secure advantaged supply.

However, I do want to caution that while the natural gas price advantage is material to our economics, it is in no way sufficient to incentivize newbuild combined cycle generation as is evidenced by our purchase price, which is at approximately 60% discount to newbuild construction cost.

As we have previously reported, the purchase price for the asset was $350 million, plus spark spread-based earnout payable only if market conditions meaningfully improve.

The spark spread-based earnout is structured at 16 months spark spread auction tied to Odessa power price and gas costs, with monthly strike pricing set at a premium to market.

The earnout will only pay out if spark spread exceeds these prenegotiated thresholds.

With the recent closing of the acquisition on August 1, we are very excited to now have this high-quality and flexible gas-fired asset in our generation portfolio.

I will now turn the call over to Bill to discuss the financial highlights from the second quarter.

Thanks, Sara.

I'll start with the financial results on Slide 13.

As Curt highlighted at the beginning of the call, adjusted EBITDA for Vistra Energy was $345 million in the second quarter and $621 million for the year-to-date.

For the quarter, TXU Energy delivered $219 million of adjusted EBITDA, very solid performance for what was a mild weather spring.

To give a better sense of the second quarter weather in ERCOT, we included a chart on the right side of Slide 23 in the appendix showing the 10-year average for combined heating and cooling degree days in the North Central Texas load bucket.

You can see that energy degree days in each of April, May and June were lower than the 10-year average, negatively impacting TXU Energy's volumes for the period.

Despite the headwinds from these mild weather conditions, TXU Energy delivered solid adjusted EBITDA in the quarter as a result of strong margins and cost management.

Moreover, Vistra Energy's net residential attrition in the quarter of only 0.15%, represents our best second quarter performance of organic customer acquisition and retention since 2008.

The retail team continues to focus on the customer experience and overall customer satisfaction levels to drive residential net attrition rate to near 0. This relentless focus on the customer experience, as evidenced by TXU Energy's customer satisfaction scores for the quarter, which were at or near all-time record highs across all major reporting categories.

Once again, our commitment to customer service, product innovation and margin and cost management have led to solid financial results for our retail segment in the quarter.

Now turning to our wholesale segment.

Luminant's EBITDA contribution for the quarter was $134 million, impressive results, given the $26 million negative impact of the Comanche Peak Unit 2 outage in June.

The negative impact of this unplanned outage was offset by favorable fuel and O&M expense, including those realized from completed OP reviews, and also by increased generation from our legacy coal fleet during the period.

Following the solid second quarter performance by our integrated portfolio, we are reaffirming our 2017 guidance in the range of $1.35 billion to $1.5 billion for adjusted EBITDA and in the range of $745 million to $925 million for adjusted free cash flow.

Now turning to Slide 14.

We have updated our hedge profile and related sensitivity as of June 30, 2017.

As you can see, we remain nearly fully hedged for 2017, materially mitigating the effect of potential natural gas and heat rate movements on our financial results for the balance of the year.

We are also now 66% hedged on a natural gas equivalent basis and 51% hedged on a heat rate basis in 2018, further narrowing the potential volatility of our future earnings profile.

Our commercial operations team has added these incremental hedges on an opportunistic basis as is our normal practice.

Last, turning to Slide 15.

Our capital structure remains unchanged from our prior earnings call.

Our pro forma 2017 net leverage remains below 2x adjusted EBITDA, even after accounting for the cash outflows related to the closing of the Odessa transaction from August 1 and the construction of the Upton 2 solar facility, which, for simplicity, we have conservatively assumed does not include any project financing.

As always, we will remain mindful of our total leverage, striving to maintain a healthy balance sheet that will afford financial flexibility in the years to come.

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

(Operator Instructions) And your first question comes from the line of Neel Mitra from Tudor, Pickering.

Your peers to the South launched a pretty aggressive margin enhancement program at the retail level.

I was wondering if you guys have done the work on that as well and if you see opportunities through analytics and various other capacities to enhance the TXU margins going forward.

Yes.

So we've done -- I think we've done a modest amount of work on it.

Obviously, we can speak to the Texas market.

I'm not -- they've got a broader retail business, so I don't know how much of what they've talked about is outside of ERCOT.

What I would tell you inside of ERCOT is, first and foremost, this is a competitive market.

So just saying you're going to increase prices will have a competitive effect to it.

And if it's not coupled with some value-enhancing product and service offering that customers value, it's purely announcing that you're going to increase prices to customers.

We wouldn't do that, Neel.

We're not going to do it, and we don't follow our competitors just because they do that.

Now I'm not saying anything about what they're doing because I don't know.

There's not a lot of detail.

Not a lot of meat on the bone on it as to what they're going to do.

What I will tell you is that we have had a leadership role at TXU Energy and constantly be on the front and offering new products and services.

And that has enabled us to basically have an industry-leading margin position in the market.

We are in the middle of several initiatives that we work on, and we just announced one recently with the solar days and free nights.

That was another step forward.

I'll tell you this, too, Neel, that this is hard work.

You kick in, it takes time.

And we would never come out and announce this stuff ahead of time, because you'd have to come up with product development based on what you think customer needs are.

You have to test it.

And before I would ever come out and tell you anything about it, I would need to see it.

We would need to see it.

We would put it in place and make sure that it's working before we would talk about it.

So that's a long way, I guess, of saying to you that you're not going to hear anything about a $200 million margin enhancement from us.

What we can tell you is we constantly work to improve our product offering.

And we've actually saw -- in 2016, you saw this.

We actually had improved margins.

We continually look to improve our margins.

And so what we'll be interested to see, though, they're smart people over there at NRG.

We're constantly mining information from others.

We don't mind being a fast follower if there's an idea we're missing.

So we're anxious to see that.

We want them to be successful, but that's just not what we would do.

And we're not so -- if anybody's waiting for some kind of announcement around that, it's not going to happen.

Okay, great.

And my second question is around the Odessa acquisition.

So you guys outlined the discounted gas that you get in the West market relative to the Waha hub.

Is that discount that you're getting wider than what other plants in ERCOT West are getting?

Or are you bullish on ERCOT West pricing?

I'm just trying to figure out the competitive advantage that you have given that Waha price sets the price of power in the West market for ERCOT.

Well, first of all, so there are various locations where gas is accessed by gas fuel generators.

Obviously, the Houston Ship Channel, which trades at just -- it's almost at parity with Henry Hub, which is, I think, right now, probably -- I think the Permian is around $0.40, $0.45, and then I think Waha is around $0.34 or $0.35.

And so Permian has got about a $0.10, I think, somewhere in that range, differential.

But I think we've said this before that what's really important is what units set price and what gas do they source from.

In Houston Ship Channel, from a gas perspective, it is where price is set in ERCOT.

And given that's the higher cost, that gives you the relative advantage if you're accessing gas from the Permian or Waha.

I'd also tell you that a lot of plant -- or not a lot -- but our plants are accessing from MidCon which is -- it's a -- it's not quite at Waha, but it's fairly close as a discount.

So we have an advantage for our assets.

And there are maybe others that have that, too.

Well, I'm only speaking to what we have.

We have an advantaged fuel position in the Permian for our assets.

And we expect that to continue for some time.

I guess, my question would be, are you viewing ERCOT as one entire market?

Or are you assuming that ERCOT West pricing converges with Houston pricing, which sources off the ship channel?

Because it would seem like if you're basing it off of West pricing that a lot of guys would get Waha pricing, right?

Or am I looking at it wrong?

Yes.

This is Sara Graziano again.

If there's no congestion on the system, then there's a single marginal generator for all of ERCOT, and that generator's cost looks at price.

And so when we're saying that we believe, in absence of congestion, that unit typically is burning ship channel gas.

And so, as you're aware, there is sometimes congestion, getting into seasons or getting out of areas with a lot of renewable generation, we model the system on a normal basis.

They keep track of that very closely.

Right now, we're seeing congestion at the Houston sometimes, which we think will be alleviated by the Houston Import Project next year.

Does that help?

Yes.

That's very helpful.

Your next question comes from the line of Ali Agha from SunTrust.

I wanted to check with you on this.

I believe in the past, you talked about, as you're looking at M&A and growing the fleet that if you were to ever look outside of Texas, the most logical way to do that would be through a corporate M&A deal with lots of synergies and other benefits as opposed to buying an asset or even a portfolio of assets.

Is that fair?

Is that still how you think about the market?

It is, Ali.

I think the reason I've said this in the past is -- and I think it still exists, although I will tell you there is a plethora of people wanting to sell assets right now in the marketplace, and that's both individual assets and then portfolios of assets.

But typically, the single asset, smaller asset portfolios that guard more people at auction and they've been sold through auctions, and you've seen this, the private equity firms have actually been very much involved in that process.

And so the relative pricing has been higher.

And then when you look at that relative to where the public companies in our sector are trading, there's clearly a discount.

Now it all has to do then with what premium do you pay and do you somehow pay a way that discount.

That's why we've always said we want to be disciplined in that regard.

And we would be fair and disciplined around that.

But the other thing, I think, that's very important is that the synergies that I think exist and we think exist in a larger scale deal is there are scale economies, especially around corporate center and support costs, those could be quite substantial.

And that's why we also look -- have looked at larger sort of publicly traded companies because there really is a big value proposition on the synergy side.

Okay.

And I guess, kind of a related question to that.

One of the other issues we've heard, one of the peer companies in the public space talked about that one of the advantages also of that sort of a transaction is more liquidity to the stock and less volatility given the lack of public floor, that sort of thing.

Is that a factor in you're thinking?

Or how important do you think that is?

Yes, it is a factor in our thinking.

I do think that the relative size of the company is important.

But I think it has to be coupled also though with a performance.

So if you're big and you're a poor performer, that won't necessarily help.

But I do believe that size, in this instance, matters.

I think it matters also not just liquidity but from the economies of scale standpoint.

So it is a function there.

I also would say that we have been pretty clear about the fact that we don't feel compelled to diversify outside of ERCOT because of our retail position.

But I will tell you that there are benefits to diversification even for a company like ours.

And I think you see this a little bit right now where weather patterns are different.

And when you're a single-state company, we got to roll with Texas weather.

And that can be different, obviously, in PJM or ISO New England in any given year, and that's helpful.

So we can see some benefits.

I think the other thing that's a benefit.

And it really kind of struck me a little bit when we dissected the NRG transformation plant is, the downside protection that capacity markets offer is pretty formidable.

You can have a low-performing, low-capacity factor set of assets and you can still have pretty good margin and revenue stream from them because of the capacity market.

And so that is something that we factor into this as well.

So we take a lot of factors in, but those are some of the other ones that we would look out.

And that's all from the diversification.

A lot of people use that word, but there are some real reasons why diversifying -- and then I'll throw the last one is just pure market -- just market rural risk and then you've got political and regulatory risk.

That one we don't feel strong -- as strongly about, and we think we're in the best market from a political and regulatory standpoint in the country.

But the other ones, I think, are pretty important.

And last question.

You've talked about now having the flexibility for share repurchases if you so choose.

Can you just update in terms of you're thinking of priority in terms of use of capital growth and acquisitions?

Are they more important?

Where would -- your margin is very strong obviously.

Where would share buybacks kind of fit in there, if at all?

How are you thinking about your prioritization of capital use right now?

Yes.

So I don't think it's a mutually exclusive thing, so -- but I would say is, is that, and I said this before as well, that I think if you're going to be an acquisitive company, you're going to try to grow, you need to grow at the bottom of the cycle.

I think we have hit, who knows whether it's the true bottom or not, but we're pretty darn close to it with -- in ERCOT now that the Exelon 2,000 megawatts have come online.

And so we believe that this would be the best time to rotate our supply base into more flexible gas assets for a variety of reasons.

So I think from a growth perspective in ERCOT, the time is now for us.

And of course, we've got some other decisions to make around our portfolio, so we are focused on that.

But that doesn't mean, given our strong cash flow and our strong liquidity position right now, that doesn't mean we could not come out also while we're pursuing that growth and do some sort of a share buyback.

Now that we are working on and we think we have a path to be able to do that, I expect us to continually evaluate a share repurchase program and be ready to do that and talk to the board about it if we decide it's the right thing to do.

I think I've also said that just a multitude of share repurchases is not a strategy.

I think if you do it because you think that you want to support the value of your stock, then you also have to support it in other ways and you've got to be able to grow.

And also to perform to show that you believe that your stock price should be higher.

So we would use it as a tool, a combination with everything else.

We're not going to do 5 of them in the next 1.5 years, but we do believe that it is something that we should take a look at and we'll continue to evaluate.

Your next question comes from the line of Shar Pourreza from Guggenheim Partners.

So most of my questions were answered, but let me touch on just one topic from a strategy standpoint.

And obviously, in the prepared remarks, you clearly highlighted that you're not compelled to diversify outside of ERCOT.

And then also -- but there is some benefits of diversification.

But then ERCOT has, obviously, above regulatory treatment there, so you kind of like the regulatory environment.

So when you think about growing outside of ERCOT, I'm kind of curious on how some of these nuclear subsidies like ZECs and ZENs and potentially stuff that's popping out of Pennsylvania and New Jersey is sort of impacting your viewpoints on whether you even want to grow outside of ERCOT in the near term while this sort of stuff plays itself out.

I think that's an excellent question, and it does play into our thinking.

We -- I also said in my prepared remarks today, and I've said this before, that for us to do something, we would have to stress the performance of any potential target with -- we'd have to look at those markets under a number of scenarios.

And they would have to be resilient, even in our mind, even in the downside scenarios.

Now look, the size of the synergies can solve a lot of that, and that's why that's so important.

But I will say that market risk and where markets are in the cycle -- and it's not just ZECs.

I worry a little bit about the continued, what we believe to be, uneconomic build of combined cycles in PJM.

I think ISO New England is in a better position than PJM right now, and I'll explain that.

But what I'll say around the ZECs, and I'll speak predominantly around PJM because it's where they're really front and center, I have very high confidence that there will be -- a mitigation measure will be put in place, something like PJM has put up on the capacity market, which will exclude effectively the nuclear assets and also remove the load, sort of the commensurate amount of load.

Now that in and of itself is not a great outcome, but it is at least a reasonable outcome.

I believe the work, though, that PJM is doing on their energy market in terms of making sure that energy price formation takes into account resources that are used to support the market but that currently do not get in to setting price in the market is, in my mind, the single most important thing that PJM can and should do.

In fact, we're going to talk about it here in ERCOT.

We think that's something that ERCOT ought look at as well.

I think that's a highly important change.

I think that PJM will get that through.

And so the solution around ZECs, while I understand why it was through courts, that the court battle is -- frankly, I think the courts were effectively saying, this isn't really our deal.

I think that both PJM and FERC will put in measures to counter it and I don't like it.

I don't like anything out of the market, but I do believe that they're going to do some good things.

I spent time with the CEO of PJM, and I feel very confident that FERC will support what they want to do there.

In ISO New England, I would tell you that I think what they're doing around their capacity market, I believe, is quite good.

And I hope that they're successful in putting that in place as well.

In fact, I think the ISO New England methodology is probably on point, more capacity marked improvement than the PJM one.

And I'll leave it at that.

But we are all over this because if we're ever going to do anything, we should know it.

And I should remind you guys, you guys know this, but I spent most of my career working in the PJM New York and ISO New England markets.

So I still have some knowledge of that.

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

Shall we view Phase 1 of the OPI as completing the optimization efforts at the fossil plants and Phase 2, more focused on the nuclear plants?

Or is there more to come on the fossil side as well?

Yes, there's more to come on the fossil side.

So I'll just say, Jim did a great job on this, but this is sort of what we -- I'll go back in the solar idea's, you've got to see it to believe it before you say it and you go out externally and you toot your horn.

We needed to make sure that we were getting this stuff inside the plant.

It's not like reducing heads.

When you say you're going to get a heat rate reduction in something, you want to see it.

You got to run for a while.

So we're just giving you guys now what we know is real and obtainable, and then we're working through the remainder.

So there can still be some that come out of Martin Lake, in Oak Grove and Sandow that we haven't put out there.

Of course, we've got other plants, too, that we're working on, including gas field plants.

And then, of course -- what's that word -- we might set our sights on Comanche at some point, too.

But there's more to come here and we expect to be able to tell you on our third quarter call.

We'll tell you more of it.

If we did decide to do some Comanche, we won't have that obviously in Q3.

But we still got more work to do.

Great.

And then on Slide 6, you said the retirement decisions would come in Q4.

Is that likely to be after the Q3 call, separate announcement?

That's a good question.

I don't know that we pinpointed it.

It may be part of that call.

So I think it very well could be.

So we haven't really had a strong discussion around that, but I'm guessing it could be commensurate with that call.

Okay.

And you mentioned you are hedging some of the summer out in 2019, 2020.

Is there any insight you can provide onto how hedged you are for those years in terms of margin?

Yes.

So hang on just a minute, we're just looking for the numbers.

Let me -- can I make one other -- oh, there they are.

So let me make one comment, though, just because I think it's important, and we have this discussion all the time internally.

I'm not sure how much we've talked about it externally.

But yes, when we wake up every day, we're sort of volumetrically -- not sort of, we're pretty volumetrically hedged for about 60% of our long position from our wholesale business because of our retail position.

The thing we haven't settled for that is what is the purchase price going to be between wholesale and retail, and that's a function of when we decide to actually lock in on retail.

We'll then have come in and hedge behind that to make sure that we have a solid transfer price mechanism in place.

So that, I think it's important for people to think about because we do have a strong volumetric hedge already.

And the economics of which just aren't settled, but it all stays within the family.

And I think that's important.

Plus -- to get to your exact question, we are about 32% -- I think we're 32% hedged in '19, about 14% in 2020 and about 5% in 2021.

What we did is, we did about 10% incremental hedging to get to those numbers in '19, about 7% in 2020 and about 2%, 2021.

And what we did, though, I just want to be clear on this, is that we just took advantage of the liquidity.

There's not a ton of liquidity in ERCOT out in those years.

But when those summers popped up, there were some players out there that wanted to transact, and we thought the prices were pretty darn attractive relative to our long-term point of view.

And as we do -- and again, we look at our -- when we're hedging, we look at a series of forward curves, whether it's 5 years out or 2 years out, and we look at the opportunity to pick from those forward curves, and we thought this was a good time to incrementally add hedges on to those years at what we thought were attractive prices.

And just to be clear, the numbers per foot were heat rate hedges and that's really where we saw the movement in the back years.

Your next question comes from the line of Steve Fleishman from Wolfe Research.

Just a couple quick detail questions.

How much is Odessa contributing to the 2017 guidance?

It's -- I think it's -- hang on just a second, Steve.

I want to make sure.

Yes, it's $15 million, Steve.

Okay.

And is -- do you have a sense of like a full year run rate?

Yes.

I think we're looking at $45 million to $50 million.

Great.

And just for the full year, I know you reaffirmed your range.

Is the segment -- at the beginning you gave like segment guidance for each one.

Are those still roughly the same ranges as well for wholesale and retail?

Yes, they roughly are.

Yes, they roughly are.

Great.

And then it seems like your volumes this year are up pretty meaningfully.

Is that just -- and even with Comanche, is that just the coal plants running a lot more than last year?

Yes.

You probably don't remember this, and I don't know how much we really talked about it.

But right at the end of '16, gas prices popped up, and our commercial team was able to go out and hedge.

And we did not go into seasonal ops for the legacy plants.

And so we were able to hedge in a positive EBITDA contribution.

And so that's why you're seeing that, because we didn't go into seasonal ops for the legacy coal plants.

We've been running them, and we expect to run them pretty much through the year.

Okay, great.

And then one last question on Odessa.

So I get the ability to get really cheap gas in that region.

Can you maybe just talk a little bit about kind of how -- where you can bring the power from that plant?

I.e., is the plant able to get access to places where power is more set based on higher-priced gas than in the Permian region?

Yes.

We are, yes.

Some of that is planned with the buildout, but yes.

Now I think that, Steve, you touched on a point that I think we're just open about is what will really be interesting to see is longer term.

And I'm talking 3, 4, maybe even 6 years out, how much renewable buildout occurs and what might happen to congestion getting from West to East.

But I think we've seen that ERCOT has been willing to make that kind of modest investment.

We're not going to talk about kind credits still here.

I'm talking kind of modest investments to make sure that plants like Odessa can get to the rest of the state.

And so we expect to be able to have freedom to move that power around to the higher-price market.

And that's what's happening now, and that's what we believe will continue to happen.

Your next question comes from the line of Michael Lapides from Goldman Sachs.

Still trying to come up (inaudible) a little bit here.

One easy question for you.

You talked a little bit about this at the beginning of the call.

How much in the off-peak hours can a generator like you guys ramp down your coal plants when power prices are weak given the amount of wind generation that hits?

I mean, are you able to ramp them down all the way or down to a 10% or 20% utilization?

Or I'm just trying to think physically how much will the machine actually let you ramp down.

So Jim can step in, but one of the things Jim talked about in our OP effort is it's called with an acronym, it's LSL.

But it's basically the lowest point where a coal plant can go down to and -- sort of physically.

And one of the keys in coal plants to try to keep them to survive, especially in Texas, is to get that LSL as low as you possibly can.

And that's what we're working on.

And so just -- we -- you cannot come down to 0. There's always some threshold for a coal plant.

And again, the lowest will be the best.

If you really want to be at 0, you got to come off, and that's an issue, right?

And you're trying not to do that with coal plants too much because that's kind of coming off and coming back on can have an issue with just the equipment and the asset.

So Jim, you want to add anything?

Yes.

It does differ by plant.

And I think one of the key successes of the OP effort has been continuing the sort of creative thinking on what would it take to actually get the LSL even lower.

And so all the plants have seen some level of improvement.

From a unit as an example, Martin Lake, they used to be at about a 50% level.

Now they're actually closer to a 25% level of max, which is a huge improvement on LSL.

And you have to be stable, not only through the steam cycle, but you have to be stable through the entire environmental controls process as well.

So you have to -- you do have to look at it end to end.

I'd say 25% to 50% range of peak is -- captures about where the units are.

Got it.

And then I have one question on the retail business, which is, we've seen lots of the other IPPs, I mean, outside of you guys and NRG.

We've seen a lot of the other guys talk about wanting to beef up their retail business.

But we haven't really seen much of an impact of that in Texas in terms of the gross margins that the former incumbent retailers earn.

Why do you think that is?

What's driving that?

What's enabling that margin stickiness for you, for NRG, for some of the other incumbents?

Well, that's a -- Jim may want it.

I could see he's chomping at the bit.

(inaudible) so -- and look, this business Jim built, so -- but I don't care, I still like to talk about it.

Well, look, I think it's complicated, but I think, in some ways, it's really not at the end of the day.

First of all, customer segmentation in broad strokes, because it's far more segmented than what I'm about to really tell you.

But I think you can take this a bit to the bank is there's kind of a segmentation around those who like named, stable product offerings, people they're comfortable with.

This is, as Jim describes it, sort of a low-involvement category product.

And so people really don't want to make -- get into the sausage making.

All you have to do is go to sort of the power queues and it will spin your head, how you make that decision.

But people really -- they're happy with the brand.

But I'll tell you, you can't just do that because of your name.

You have to do it because you have a product offering that people are comfortable with.

And we've gone to great lengths to provide people with stable pricing and a stable product offering, and then we've also given them products that meet their needs.

And we proactively go to them if we see that there are products that they shouldn't be on and maybe they use a lot of power overnight or something.

We'll proactively try to get them on free nights or something.

So I think there's a lot to it, and it's not just advertising.

This is pure data mining.

This is a very analytical business, understanding your customers, understanding their needs and proactively coming up with products they need.

There's no smoke and mirrors in this.

This is a real retail marketing business.

We've just been very good at that, and we've been out in the front on it.

And so that's really been good for us.

Now we have entered into what I'll call the other segment, which is -- had greater -- not -- because there's variation of this segment, too, by the way.

But are more inclined to switch and more inclined to look, and we've got a brand out there we've had a for a while, had great success with called 4Change.

We've got another brand out there called Energy Express.

And those go after folks that are inclined to switch but also, just may -- they might want -- they don't want to be involved with anybody, right?

They just want to do something online and just be -- and make it easy.

And so -- and then they're more price-conscious, and that's about 35% of the market.

And about 65% of the market is more of the brand-name customers that we have.

So that's a lot of meat, but let me -- Jim, I think you'd be good if you want to add anything there.

Sure.

I think you summarized it well.

I would first start out by saying that it is actually very easy to enter the retail space, but it's very hard to be successful at it, because there's very low barriers to get started.

And we sometimes talk about all you need is a laptop computer and a couple of people and you can launch a retail.

But to actually operate, as we talked about on the last call, scale does matter in this business.

It matters because you do need to make significant investments in your service platform, your billing systems, your risk management systems, and then your product innovation and your service offering.

The kind of products that we launched, for instance, off of the solar development that Sara had talked about.

The solar days and free nights is not something that you can just put a billboard up.

You got to be able to operationalize that product, market it effectively and innovate.

And that is a better-than-average margin product.

And so I think the key to this business at the end of the day is very similar to every other competitive market where there's a willing buyer, willing seller, where a supplier has to get through the clutter and compel a customer to choose them.

So there's a lot of people that are entering, and the space is getting more and more crowded, which means that having a differentiated proposition in our brand is even more important.

So the fact that more are entering does not necessarily mean higher success rates.

In fact, I would say it challenges it because the field, at the end of the day, has ample, ample choice and the next guys coming into the fold have to really do something special to stand out.

And so kudos to actually hundreds and hundreds and hundreds of people that support TXU Energy, both internal employees, that's our workforce, but also our vendor and sort of business partner network.

You can't stand one of those up overnight.

And so I really do want to commend the team for building what I believe is a very sustainable business in a very low-cost platform.

And so we welcome the competition.

It's just part of what we've grown to do and actually, frankly, love.

But it is a good business to be, and we're happy to have the balanced model that we have between the generation and the retail.

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

A question on -- I'm wondering if you can clarify your comment that future renewables buildout would contribute to congestion and eventually to more transmission.

Until that new transmission is built, how does that affect economics of Odessa and other power plants in the region?

Well, what I was saying is that we don't have a crystal ball.

We don't know how much is going to happen.

I mean, we model and we model our economics, and we looked at several scenarios.

But we modeled continued build of solar and wind.

So -- and so the economics behind what we have today has that in.

My only point is, depending on what that looks like and how much it might be, you could run into a constrained situation.

Our modeling, which you would think is reasonable, does not have that.

And so any sort of constraint, we just -- we don't see that.

I just want to be (inaudible) caution.

We also will be open about it that, that could happen because you bring a lot from the West parts of the state trying to get it over to the East.

Depending on what that buildout would look like, it could have an impact.

And that was the issue.

Sara, go ahead.

I was just going to add that, as I'm sure you know, and as a gas-fired combined cycle, Odessa is a very flexible asset.

And so we can ramp down, we can turn off completely at night and start up again in about an hour and 15 minutes.

We can that up and running again in the morning.

And so we actually believe that Odessa is going to be a critical asset for ERCOT to balance the wind and increasing solar penetration.

Okay.

That's a good point.

Hey, another quick question.

On the -- on Slide 15, the capital structure.

I've noticed that the cash and cash equivalents forecasted for the year are $1.2 billion.

It used to be $1.8 billion in the first quarter presentation.

I was expecting some reduction there for the Odessa purchase, but that's -- I think that's a little bit higher than what I was expecting.

What else is contributing to the decline there?

It's a couple of things.

It's -- we also have the expenditures for Upton 2, which, as I mentioned, we're assuming we're not arranging any project financing.

So the total Upton 2 expenditures were around $200 million, just a little under maybe.

Due to time, our last question will come from the line of Amer Tiwana from Cowen and Company.

My questions have been answered.

And there are no further -- sorry.

No, go ahead.

There are no further questions at this time.

I will now turn the call back over to Curt Morgan, CEO.

Thank you for taking the time to join us on the call today.

We really appreciate your interest in our company.

As I stated at the beginning of the call, we do appreciate the interest in Vistra Energy and the support, and we're looking forward to continuing the conversation about our company.

And until next time, I hope everybody's well.

Thank you.

This concludes today's conference call.

You may now disconnect.