瓦萊羅能源 (VLO) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to Valero Energy Corporation's Third Quarter 2019 Earnings Conference Call.

(Operator Instructions) Please be advised that today's conference may be recorded.

(Operator Instructions) I'd now like to hand the conference over to your speaker today, Mr. Homer Bhullar, Vice President, Investor Relations.

Please go ahead, sir.

Good morning, everyone, and welcome to Valero Energy Corporation's Third Quarter 2019 Earnings Conference Call.

With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jason Fraser, our Executive Vice President and General Counsel, and several other members of Valero's senior management team.

If you have not received the earnings release and would like a copy, you can find one on our website at valero.com.

Also, attached to the earnings release are tables that provide additional financial information on our business segments.

If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.

I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC.

Now I'll turn the call over to Joe for opening remarks.

Thanks, Homer, and good morning, everyone.

We're pleased to report that we delivered solid financial results despite challenging market conditions again this quarter.

Although gasoline cracks held steady and diesel cracks improved from the previous quarter, heavy and medium sour crude oil discounts to Brent crude oil remained narrow as supply was constrained by geopolitical events.

Also, the startup of new pipelines from the Permian Basin to the Gulf Coast tightened the WTI Midland to Cushing crude oil differential.

Despite these headwinds, we generated $1.4 billion in operating cash flow, once again demonstrating the flexibility and strength of our assets to deliver steady earnings and free cash flow.

During the quarter, we began to enjoy the benefits of our investments in the new Houston alkylation unit that was commissioned in June and from the recently completed Central Texas Pipelines and Terminals project.

The alkylation unit upgrades lower-valued natural gas liquids and refinery olefins to a premium, high-octane alkylate product.

And the Central Texas Pipelines and Terminals reduced secondary cost and extends our supply chain from the Gulf Coast to a growing inland market.

Other strategic growth projects in execution remain on target.

The Pasadena Terminal, St.

Charles alkylation unit and Pembroke cogeneration unit are expected to be completed next year, with the Diamond Green Diesel expansion expected to be completed in 2021 and the Port Arthur Coker in 2022.

In September, our Diamond Green Diesel joint venture initiated an advanced engineering and development cost review for a new renewable diesel plant at our Port Arthur, Texas facility.

If the project is approved, construction could begin in 2021 with operations expected to commence in 2024.

This would result in Diamond Green Diesel production capacity increasing to over 1.1 billion gallons annually.

The guiding framework underpinning our capital allocation strategy remains unchanged.

We continue to expect our annual CapEx for both 2019 and 2020 to be approximately $2.5 billion, with $1 billion allocated for projects with high returns that are focused on market expansion and margin improvement.

During the third quarter, we returned $679 million to stockholders, which represents a payout ratio of 61% of adjusted net cash provided by operating activities.

We continue to target an annual payout ratio of 40% to 50%.

Looking forward, we're encouraged.

Fourth quarter market conditions are favorable.

Distillate and gasoline margins are significantly higher than last quarter and this time last year, supported by strong fundamentals, good demand and wider medium and heavy sour crude oil discounts.

In closing, our team's simple strategy of striving for operational excellence, investing to drive earnings growth with lower volatility and maintaining capital discipline with an uncompromising focus on shareholder returns has proven to be successful and positions us well for any market environment.

So with that, Homer, I'll hand the call back to you.

Thanks, Joe.

For the third quarter of 2019, net income attributable to Valero stockholders was $609 million or $1.48 per share compared to $856 million or $2.01 per share in the third quarter of 2018.

Operating income for the refining segment in the third quarter of 2019 was $1.1 billion compared to $1.4 billion for the third quarter of 2018.

The decrease from the third quarter of 2018 is mainly attributed to narrower crude oil discounts to Brent crude oil.

Refining throughput volumes averaged 2.95 million barrels per day, which was 146,000 barrels per day lower than the third quarter of 2018.

Throughput capacity utilization was 94% in the third quarter of 2019.

Refining cash operating expenses of $4.05 per barrel were $0.33 per barrel higher than the third quarter of 2018, primarily due to higher maintenance activity and lower throughput in the third quarter of 2019.

The ethanol segment generated a $43 million operating loss in the third quarter of 2019 compared to $21 million in operating income in the third quarter of 2018.

The decrease from the third quarter of 2018 was primarily due to lower margins resulting from higher corn prices.

Ethanol production volumes averaged 4 million gallons per day in the third quarter of 2019.

Operating income for the renewable diesel segment was $65 million compared to a $5 million operating loss in the third quarter of 2018.

Renewable diesel sales volumes averaged 638,000 gallons per day in the third quarter of 2019, an increase of 387,000 gallons per day versus the third quarter of 2018.

The third quarter 2018 operating results and sales volumes were impacted by the planned downtime of the Diamond Green Diesel plant as part of completing an expansion project.

For the third quarter of 2019, general and administrative expenses were $217 million, and net interest expense was $111 million.

Depreciation and amortization expense was $567 million, and income tax expense was $165 million in the third quarter of 2019.

The effective tax rate was 21%.

With respect to our balance sheet at quarter end, total debt was $9.6 billion, and cash and cash equivalents were $2.1 billion.

Valero's debt-to-capitalization ratio, net of $2 billion in cash, was 26%.

At the end of September, we had $5.4 billion of available liquidity, excluding cash.

With regard to investing activities, we made $525 million of capital investments in the third quarter of 2019, of which, approximately $305 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance.

Net cash provided by operating activities was $1.4 billion in the third quarter.

Excluding the impact from the change in working capital during the quarter, adjusted net cash provided by operating activities was $1.1 billion.

Moving to financing activities.

We returned $679 million to our stockholders in the third quarter.

$372 million was paid as dividends with the balance used to purchase 3.9 million shares of Valero common stock.

The total payout ratio was 61% of adjusted net cash provided by operating activities.

This brings our year-to-date return to stockholders to $1.7 billion and the total payout ratio to 54% of adjusted net cash provided by operating activities.

As of September 30, we had approximately $1.7 billion of share repurchase authorization remaining.

We continue to expect annual capital investments for both 2019 and 2020 to be approximately $2.5 billion, with approximately 60% allocated to sustaining the business and approximately 40% to growth.

The $2.5 billion includes expenditures for turnarounds, catalysts and joint venture investments.

For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.71 million to 1.76 million barrels per day; U.S. Mid-Continent at 410,000 to 430,000 barrels per day; U.S. West Coast at 260,000 to 280,000 barrels per day; and North Atlantic at 475,000 to 495,000 barrels per day.

We expect refining cash operating expenses in the fourth quarter to be approximately $3.95 per barrel.

Our ethanol segment is expected to produce a total of 4.3 million gallons per day in the fourth quarter.

Operating expenses should average $0.39 per gallon, which includes $0.06 per gallon for noncash costs such as depreciation and amortization.

With respect to the renewable diesel segment, we still expect sales volumes to be 750,000 gallons per day in 2019.

Operating expenses in 2019 should be $0.45 per gallon, which includes $0.16 per gallon for noncash costs such as depreciation and amortization.

For 2019, we expect G&A expenses, excluding corporate depreciation, to be approximately $840 million.

The annual effective tax rate is estimated at 22%.

For the fourth quarter, net interest expense should be about $113 million, and total depreciation and amortization expense should be approximately $565 million.

Lastly, we still expect the RINs expense for the year to remain between $300 million and $400 million.

That concludes our opening remarks.

(Operator Instructions)

(Operator Instructions) Your first question comes from the line of Neil Mehta with Goldman Sachs.

Let me start off with the obligatory IMO 2020 question.

The cracks, obviously, are very strong.

We're seeing spreads widening out.

How much of strength you see on the screen do you think is a function of just turnaround activity versus something that's the beginning of a more sustainable IMO impact?

And maybe the 30,000-foot question here is, how do you think IMO plays out, for the sustainability and the depth of impact, as we think about your model over the next couple of years?

Okay.

Gary, you want to?

Yes, Neil, I think the products' cracks, it's pretty difficult to be able to determine how much of the strength in the crack is IMO related and how much is just fundamentals and supply.

But we're certainly seeing a lot of indications in the market of IMO starting to impact it.

The thing that I would point to, the diesel curve is just continuing to shift higher the closer we get to the January 2020 date.

On the gasoline market, we're seeing indications as well.

Our view was, if you would see some of these low sulfur feedstocks to cat crackers being pulled out of the cats and put into the low sulfur bunker market.

If you look today, low sulfur VGO was $5 over gasoline in the Gulf, which is to the point where you'll start to see people pull that out of cat crackers and put it into the low sulfur bunkers, which should impact gasoline yield moving forward.

And then the big thing that I think is very visible is on the feedstock side of the business.

High sulfur fuel oil, it traded as high as 95% of Brent earlier this year, this morning, trading at 61% of Brent.

The forward curve on high sulfur fuel oil was backwards, indicating it's going to get weaker as we go forward.

And as you would expect, as high sulfur fuel oil has traded weaker, we're starting to see that in the crude quality discounts.

So through most of the year, we've had heavy sour trading inside of a 10% discount to Brent.

It's almost 20% discount to Brent today.

Maya and WCS.

I think Maya trading at 11.50% discount to Brent today, and we're seeing medium sours get weaker as well.

So I think on the feedstock side of the business, it's pretty clear, we're getting an impact not as clear, but I think we are also seeing it on the product side.

And then the follow-up question is around renewable diesel.

Maybe, Joe, if can you just talk about how you see this part of the business fitting into your long-term strategy, and then how you think about the gating factors for adding that capacity that you talked about in the call, and then anything around Blender's Tax Credits.

So a lot of pieces to that, but just if you can fill in the gaps as it relates to renewable diesel because we think it's going to be an important part of the story going forward.

Yes.

I mean you took a book out of Paul Cheng's -- page out of Paul Cheng's book here.

You've got those three questions in there.

I'll speak about part of it, I'll let Martin speak about part of it, and then Jason might want to cover kind of the probabilities for the Blender's Tax Credit.

But I mean strategically, we're a company that really makes motor fuels.

And we're a company that takes their environmental responsibilities and sustainability very seriously.

And so when we look at the opportunities to produce products where there's going to be growth in the market and they're going to have sustainably high margins, we look to renewable diesel.

We just think it's a really good business.

We've got a really good partner in Darling, and it's something that we know how to do.

We know how to run these processes very well.

And so it fits right down the middle of our fairway, and so we feel very good about not only the returns but the overall EBITDA contributions that we're going to get from this product for a very long time to come.

So Martin, you want to cover [a piece of it]?

Joe, thanks.

Yes, we're bullish on renewable diesel.

We expect demand growth to be strong.

You've got the Renewable Energy Directive II in Europe now that's been extended to 2030.

The California LCFS has been extended out to 2030 and calling for a 20% greenhouse gas reduction in 2030.

And then the recent elections in Canada would tell us we're probably going to see a national standard in Canada, too, and then you've got New York State.

So we think the future demand for renewable diesel just looks very strong.

Do you want to talk about the Blender's Tax credits?

Yes.

This is Jason.

I'll give you an update on the Blender's Tax Credit.

As you all know, it expired at the end 2017.

Both chambers of Congress have proposed legislation that would extend it.

I think the Senate has got it going out for 2 years, and this was back retroactive to 2018.

And the House for 3 in negotiations on the BTC and other tax extenders are now taking place within the context of the appropriations process.

We're optimistic it will get done because the BTC remains one of Finance Chairman Grassley's top priorities, and there's really not lot of opposition to it.

However, this impeachment process is certainly interfering with the bipartisan cooperation that you need to get the package agreed to.

So it's what created a little more uncertainty than there was before.

Neil, one other point I think I would like to make on this, Martin can you speak to why isn't -- why aren't we doing like 200,000 barrels a day of this?

I think that the only constraints you look at is in the waste feedstock market, and we're confident we can source it and we're not worried about that anytime soon, but that's the ultimate constraint on this is the feedstock.

The feedstock supply is tied to global GDP per person.

This waste feedstock, that's increasing, so we feel good about being able to source the feedstock.

And our partnership with Darling, they're a global leader in this.

They process 10% of the world's meat by-products.

And so we're in a good place on securing the feedstock.

Our next question comes from Roger Read with Wells Fargo.

I guess a couple of things to dig into a little maybe more on the macro front.

Just in terms of product demand, I recognize you can't give us absolute clarity on what's driving what.

But we've got good cracks on even the light crude.

So in spite of IMO, things were better.

I was just curious, maybe getting back to Neil's question there on how much of this might be turnarounds versus what we're actually seeing in terms of a solid backdrop on the demand front?

Yes, Roger.

So I think, to me, if you look at product inventories and you roll back to early August, total light product inventory was 16 million barrels above where we were in 2018 at the same time period.

Now over the last 2 months, we've had significant product growth such that in the last set of stats, we were 19 million barrels below where we were in 2018.

So in a period of just a couple of months, you've had a year-over-year change in total light product inventories of 35 million barrels, which is a pretty staggering figure.

And so if you look at that, break it down, we se good demand, vehicle mile travel look good, the tonnage index looks good, but then there are certainly some things that are supply driven as well.

Shut down of PES, some planned and unplanned refinery outages have driven that as well.

It helped support product fundamentals.

But moving forward, you look, and gasoline's sitting just a little above the 5-year average range.

Diesel is at the lower end of the 5-year average range.

On apparent days of supply, both gasoline and diesel, below the 5-year average range.

So the fundamentals look very good for both gasoline and distillate moving forward.

Okay.

Great.

And then just a couple of follow-up on that.

We've obviously seen this issue on the tanker market.

Part of that is clearly related to IMO, with ships going into the dry docks for retrofitting on the scrubbers.

But I was curious, as we look at the risk of some of these product tankers on the clean side moving into the crude markets chasing rates, do you think we're at any legit risk of tightness in product tanking markets that could impact your export story as we go forward?

Yes.

And Roger, I think for us, most of our exports are short-haul market.

So we're primarily going to Mexico and South America.

As freight rates spike, it actually gives us a competitive advantage for other people trying to get to those markets.

So I don't really know that it's much of a risk to us.

Our next question comes from the line of Manav Gupta with Crédit Suisse.

I had a quick macro question first.

Can you talk about -- a little bit about the limitations of very low sulfur fuel oil at this stage?

I'm trying to understand, would shippers be more comfortable with sticking to the tried and tested Marine gas oil?

Or would they actually be looking at very low sulfur fuel as a cheaper substitute in the initial stages of IMO?

Yes.

So we have a compliant blend that we are offering in the Corpus Christi market.

We're also proceeding with a project, where we'll be able to have a low sulfur blend in Pembroke.

But we also have seen that there's a lot of challenges on being able to blend this 0.5 material, especially with a lot of the low sulfur paraffinic crudes.

So I think there is a good chance that initially, ships will run marine gas oil and then gradually transition to the lower sulfur bunker material.

And as I understand, that would be good for the U.S. diesel demand, right, if they continue to use marine gas oil in initial stages?

Yes, it will.

And I think even with the blend we're seeing on the low sulfur bunker material, those blends still contain a fairly significant percentage of distillate in the blend.

And so even if they're burning the low sulfur bunker, we'll still see a step change in diesel demand.

A quick follow-up is you are running a lot of light sweet crude on the Gulf Coast, almost 770,000 barrels a day, up about 25% versus last year.

I'm trying to understand now that you're finally seeing solid discounts widen out, should we think that in 4Q and going ahead, a little bit of a switch back to medium and heavies, which would also solve some of the naphtha issues you had in 2Q?

Yes.

So that's exactly what we see.

We set another record for light sweet crude processing in the third quarter.

The economics there goes strongly in favor of light sweet crude.

We've been saying that we've got 1.6 million barrels a day of overall capacity, and we pretty much fully utilized at in the third quarter.

But certainly, with the widening of the quality discounts, especially the heavy sour crude are favored, then we're starting to see medium sour crudes become economic as well.

Our next question comes from Philip Gresh with JPMorgan.

A bit of a follow-up to Manav's question here, just in terms of your slate on the Gulf Coast.

How do you think about your ability to run high sulfur fuel oil as a feedstock?

I think residuals have been about 200,000 barrels a day or so each of the past 2 quarters.

How much of that is high sulfur fuel oil, and what kind of flexibility do you have to run more as a feedstock?

So we have a lot of flexibility to do that, and we have been doing some of it backing out high sulfur or heavy sour crude.

And we haven't really been running high sulfur fuel oil, but we've been running blend components that are going into the high sulfur fuel oil market.

And we've run some of those, and we expect to do more as we move forward.

Okay.

And then second question, obviously, there was a change to the Maya formula.

But obviously, Maya has to be competitive regardless of what the formula is.

So I'm just curious how you're thinking about how these heavy barrels in the Gulf Coast need to price, especially WCS, which seems to be discounting more as more barrels are coming via rail, but also then you have the Middle Eastern barrels, you have the medium sours, so how do you think about how this should all price relative to each other?

Yes.

So we believe heavy Canadian and Maya should trade at approximately the same value.

Obviously, in September, PMI expected high sulfur fuel oil to trade much weaker, and the formula had Maya really priced out of the market.

But they made the correction in October, and if you look at where both WCS and Maya are trading today, they're almost on top of each other, which is where we expect those to trade moving forward.

Our next question comes from Prashant Rao with Citigroup.

After following up on Phil's question there.

Price on Maya and WCS is one factor, relatively how those are on top of each other.

But in market access, barrels that are moving down of the Gulf is another.

As we're looking to -- Canada is talking about rail above curtailment.

We're starting to see curtailment entry, curtailment starts to roll off a little bit.

It looks like we could be getting more barrels of Canadian into the Gulf Coast market.

I just wanted to get a sense of what you're seeing out there, and if you can maybe give us a sense of what you can get on sort of a firm versus delivered basis per barrels?

And how does that play further into kind of that Maya versus CS dynamic, right, for pricing at the Coast?

Yes, so we're in ongoing negotiations with several producers in Western Canada on delivered rail volume.

We have our Lucas rail facility that feeds the Port Arthur refinery and a lot of capacity to run heavy Canadian there.

And we anticipate, as we move to the fourth quarter, you'll see rail volumes ramp up.

And we anticipate we'll buy those barrels delivered on something equivalent to the WCS or Maya quote in the Gulf.

Okay.

Great.

And then other factor -- another question, just to follow up on that ethanol.

That's a smaller segment, but just wanted to get a sense of how you see the next couple of quarters playing out, And when we get could start to see, potentially, EBIT going back into the black on ethanol?

What do we need to see to sort of give us the first signpost that, that swings to positive because obviously, there could incremental upside there too in the quarters ahead if factors play out right.

So this is Martin.

I think, near term, October is looking a lot better than the third quarter did.

What you've seen is the recent DOE data.

What the issue's been is oversupply in the U.S., right?

Inventory is just too [high](corrected by the company after the call), which is pressuring margins.

The production is trending lower.

Ethanol inventory now in the weekly data is 2.5 million barrels lower than this time last year.

And then long term, we're still bullish.

Ethanol is going to be in the U.S. gasoline mix for the long run.

We expect to see some small incremental demand in the U.S. from higher octane and fuel efficiency standards and some small incremental demand from year-round E15 sales.

And then we expect -- really, the big thing we expect is a rebound in the export growth due to favorable blend economics, just the economics of blending ethanol and then these global renewable fuel mandates.

So we still feel very constructive in the long term, and I think that's going to be around the corner.

Our next question comes from Paul Cheng with Scotia Howard Weil.

I think I have 2 questions.

One maybe is for Gary, I think.

You can start.

I will try to stick to just 2, not more.

Gary, you mentioned that you haven't really [sent] (corrected by the company after the call) the high sulfur resid directly to the coker.

Is that something that you guys believe technically given the right economics you can do?

And does it matter whether it's a delayed coker or it's a fluid coker?

Paul, Lane.

I'll talk.

We historically ran quite -- what Gary was talking about was we run a lot of, I would say, blend stocks that go on a 3.5 weight percent fuel oil.

We've always done that, and we -- it's part of the market that we feel like we understand technically, maybe better than a lot of the people in the industry.

And one of the critical strategy of going into this towards going into IMO is to make sure you keep connectivity between these feedstocks and the heavy crude, and we worked really hard doing that.

There are technical challenges.

They are around desalting and some of the other things.

But we are very focused on increasing on heavy sour resid that we run.

So you're saying that you run the heavy sour, the crude or do you run the heavy sour resid?

We do both.

Your question was around resid, and so the question -- the earlier question was are you running more fuel oil?

And we don't really run fuel oil per se.

What we run is we run the blend stocks that go in the 3.5 weight percent.

And so as you see that, as people unwind that as a fuel oil, you're going to see more of these components around the world become available.

And the key to be going out there and understanding them technically and fitting into our system, which we're working very aggressively to do that.

How about the second part of my question, whether that make any difference that -- whether it's a fluid coker or a delayed coker in your ability to run those?

Not really.

Not really?

Okay.

No.

And then, Joe, for -- you have strong cash flow and continue to do so.

Your balance sheet is in good shape, but given the uncertainty in the economy, would that make sense to move part of the free cash to pay down debt to really join down the debt to a much lower level at some point that we may get hit by recession we don't know when, but at some point it may?

Yes.

It's a good question, Paul.

We'll let Donna speak to that.

No.

I actually think our balance sheet is in good shape.

We do have additional debt capacity to go.

I don't think our ratings are in jeopardy.

We have good liquidity today.

So again, I'm not -- don't believe that paying down debt right now is necessary.

Yes, there's really none that you'd call as...

Well, it's very expensive.

You're right.

Our next maturity is in 2025 and to try to get that called early will be expensive and uneconomical to us.

Your next question comes from Doug Leggate with Bank of America.

So I just got 2 quick questions, Joe.

Obviously, IMO is the focus of the whole market right now, and my question is really more about just your perspective on duration of any perceived benefit.

To give a -- to swing my question a little further, our view is that the industry can react to the product side of it, but things like your VGO, or reallocation, things about that nature, the stickier side of it seems to be on the sour feedstocks.

So I just want to get your perspectives.

Do you think that the product side of it is more sticky as well?

In which case, what does it mean for, like, gasoline balance given what you described in your prepared remarks about VGO?

Maybe explain your experience on what you have done with VGO on how you expect it to operate going forward?

And I've got a quick follow-up afterwards.

Gary and Lane can speak to this.

Paul -- I mean Doug, excuse me, if you recall, for -- probably for 18 months or something, we've been talking about the prospects from IMO.

And it's kind of shaping up the way that we had anticipated.

The one issue, and the guys can speak to this in addition to your question, is how do you solve the circumstances that IMO creates in the market, okay?

Who comes in and solves the problem around the 3.5% weight fuel oil.

So you guys wanted to speak to it in general and then...

I'll start, and then, of course, Gary can always tune me up a little bit later here.

But as Joe alluded to, this is -- we've all -- this sort of played out the way that we thought.

And I think, ultimately, over -- early on, you're going to have this demand for diesel.

It'll be interesting to see how long that goes.

I mean it could go on for quite some time, depending on the technical difficulty of [Jim] making those fuels.

And we have seen some of that, like Gary alluded to.

This is not an easy task to create, to make all these fuels work from a compatibility perspective.

But longer term, the 3.5 weight percent, I'm making that and I'm having a home for it is a much -- is a capital -- a much more capital-intensive thing to try to work through.

And somebody alluded to it -- was asking the question earlier about valuations of the crude.

What will be interesting is right now, we say these crudes are -- to the extent that heavy sours and medium sour are running not -- they're not being valued based upon an open coker, but they're being valued based on 3.5 weight percent, you could see -- you're going to see that disconnect, even get greater.

I don't know that we know you can think about all the paths to try to close that gap, but it all takes quite a bit of capital.

Yes.

I think a lot of uncertainty.

We certainly anticipated -- you'd see scrubbers come online.

But there's a lot of technical issues around the scrubbers that maybe they don't come on as fast as what we thought.

And then the other area here that with uncertainty is when does some of this production that's off-line, some of these medium and heavy sour crudes, when do they come back on the market.

So very difficult to give you a time line.

It's not a problem that's going to get resolved very quickly.

I think, again, we've always kind of played down the whole product side of this, but I think we've expected more on the feedstock side.

We're seeing it in both right now, but it's just going to take a while to solve.

I know it's a really tough one, but obviously constructive for you guys in particular.

My follow-up, and either Joe or Donna, whoever wants to take this.

But the balance between buybacks and dividends specific to Valero, you're operating better than any other refinery in the industry, frankly, in terms of your execution, your reliability in terms of markets, consistency of delivering to the market.

But your buyback and dividend is still pretty skewed, I guess.

What is the right level for that, especially as your share price goes up too?

I know you've always been pretty sensitive to buying back stock.

When you get this kind of periodic strengthening and margins in the industry.

So do we see a step up in the dividend or maybe a rebalancing of how you return cash?

And I'll leave it there.

Yes.

No, we'll let Donna talk to this because, I mean, Doug, obviously, there's not a formulaic approach to how you do this, right?

I mean you've got to have your outlook for the market going forward.

Obviously, we felt it's been pretty good.

That's why we have significant dividend increases we have.

And you want to be competitive from a yield perspective not only with your peers but with the broader market.

So all those things can take into consideration.

But Donna, as far as the mix...

Yes.

So I mean we do view that dividend as a very important part of the total shareholder return, but it's also important to us that it is sustainable.

So we want to be very competitive in the market, generally, and specifically against our peers, but we also want to be able to sustain that dividend through earnings cycle.

So we always continue to look at that mix and we always continue to review it.

Yes.

And you noticed that we did more on the buyback side this quarter than we did the previous quarter.

And we haven't altered our approach.

We say we look at ratability plus, we look at buying on dips.

And frankly, we had a situation where we're looking into a strong fourth quarter with the prospects for IMO.

We said it's a good time to buy back more shares.

So that's what we did in the third quarter.

So we took advantage of an opportunity, and we'll do that going forward.

Could we expect the buyback to slow if you did?

Let's say, you're 20% higher, would you still be buying back your shares?

If we were 20% higher?

It all goes to...

This is a cyclical business, obviously.

So buy back, you know at some point, it's going to drop again probably.

So I guess how do you respond to continued strengthening?

So -- well, we are going to adhere to our 40% to 50% payout ratio.

And Doug, it doesn't make sense in this business to jostle things around on an ongoing basis.

You set your targets and you work to achieve them, and it gives you consistency not only with what the financial markets can expect from you, but operationally, what you can afford to invest in and how you can grow the business.

And so that's why we've set this capital allocation framework in place several years ago, and we've adhered to it totally since then, and it seems to work out.

So don't make me forecast dividend increases and all that.

Just rely on the fact that we have told you what we're going to do, and we're going to do it.

Our next question comes from Sam Margolin with Wolfe Research.

I have a follow-up on renewable diesel.

Actually, it's -- the location of the project you're evaluating at Port Arthur, in the context of the comments around feedstock constraints, can you just talk a little bit about why that location is a good one?

It seems like you're operating places that might have more local biomass.

Are you importing?

Or is it the marketing thing, where you're exporting?

I'm asking because as this business scales, it'd be good to know sort of the factors you look at for performance.

Yes.

This is Martin.

I mean the thing that helps renewable diesel being colocated with the refineries, so that's probably the primary thing we're looking at and a place where we can hit all the markets, so that really drives you to the Gulf Coast.

And we're driven in the United States just because of the feedstock supply in the U.S. per installed base of renewable diesel is better than anywhere else in the world.

So that's why we're heading to reviewing Port Arthur and doing the engineering analysis on it.

Okay.

So it's a combination of placement and feedstock?

That's helpful.

And then we're like 6 weeks since the Abqaic stabilizer went down in Saudi.

People who count the ships coming out of the Gulf see stable exports.

But can you talk a little bit about what you're seeing as far as high sulfur, the sour crude supply, if there's been any change in mix from the Middle East as far as feedstock quality or crude quality that you're seeing in the interim here as that facility gets repaired?

Sam, this is Gary.

We haven't really purchased any Saudi volume in quite some time.

And so I can't really give you a comment.

We're running some Iraqi and Kuwait, primarily to the West Coast, which has been unaffected.

But we don't see any Saudi volume coming into our system at all.

Our next question comes from Brad Heffern with RBC.

A question on exports.

So when I was looking at the numbers for last year for the third quarter, I think you guys exported over 400,000 barrels a day.

This year it was just a little over 300,000.

Is that demand pull into the U.S.?

Is that export weakness?

Or is there some other factor there I'm not thinking of?

Brad, I think you've kind of hit on it.

The only thing I would tell you is Port Arthur is one of our large export locations, and we were doing some dredging work on the dock there, which did limit us a little bit.

But the big driver was what you pointed to, and that's an optimization for us, and it is demand pull.

And with the large light product inventory draws we saw on the U.S., we had a better netback going into the domestic markets, and that's what drove it rather than lack of demand into the export markets.

Okay.

Got it.

And then a question on refining OpEx.

So this quarter, just the nominal number was $1.1 billion.

When I think back a couple of years ago, it used to be in the $900,000 or even the high $800,000 sometimes.

Is there any underlying factor that's driven that higher OpEx number?

I would -- it's easier for me to sort of compare it to year-over-year.

This is Lane, by the way, Lane Riggs.

And we -- our volumes were down in the third quarter, largely had 3 external power failures, and we had some storms to deal with that went through and affected our Port Arthur operations, where volumes weren't as high as they would be.

Part of that is just on a per barrel basis.

It's a little bit higher, and then some other things.

We've changed what is in and out of our operations.

We did have the MLP out.

Now it's back in.

We have Diamond Green Diesel, which used to be in.

It's out.

So there are some changes like that, that's occurred over time as well.

And nothing structural?

No, nothing structural.

Our next question comes from Jason Gabelman with Cowen.

I wanted to follow-up on something Roger Read asked around, the higher shipment rates.

Obviously, there's some near-term volatility in those rates, but I think the market is expecting shipping rates, both on the crude and product side, to be structurally higher than they were in kind of the first half of this year.

Can you just talk from a totality perspective for Valero how those higher rates impact the company's earnings, I guess, both on the product side and maybe lifting global refining margins, and then also on the feedstock side and the higher landed feedstock cost?

Sure.

I'll start on the feedstock side.

Obviously, with diet that we've been running, we're running a lot of pipeline delivered crudes and then a lot of the barrels we're getting over the water short-haul barrels.

So we don't see a big impact on our feedstock cost.

And similarly, on the products, the barrels are going into domestic markets where we export to fairly short-haul locations in Mexico and South America.

So not a material impact.

Some of the long-haul barrels that we do run, we do have some freight protection on those as well, which helps.

Obviously, the big thing that we've seen is -- has been positive to the business.

Freight rates has spiked.

Joe mentioned in his opening comments that the Brent-TI spread had come in, with the pipeline capacity coming online.

But with the freight rates spiking, we've seen Brent-TI blow back out some and back over $5, which obviously gives you as refining a significant advantage on running light sweet crude.

And as I mentioned previously into our export locations, when you're going to Mexico, the higher freight rates actually give us a competitive advantage over some of our global refining competitors trying to import to those markets.

All right.

I appreciate that color.

And then if I could ask just on the Syncrude market and kind off the northern crude market, because I know you guys run a decent amount of Syncrude to Quebec.

It seems like there's going to be some changes in the balances in terms of -- and operator maybe using less Syncrudes for diluent and then the northwest refinery up there switching from running Syncrude to WCS.

Do you see a shift in kind of the pricing paradigm for Syncrude and maybe that bleeding into Bakken emerging over the next few months into 2020?

Well, it's interesting.

Syncrude, obviously, in an IMO environment could be a premium-priced crude.

So we have a lot of optimization opportunities on what we send to Line 9. And I think our view would probably be -- we see a little bit more Bakken than we've seen in going to Quebec as we move forward in an IMO environment.

Our next question comes from Patrick Flam with Simmons Energy.

My first question is basically, I was hoping you guys could frame up your thoughts around the recent proposed changes to the RFS program.

Obviously, you guys are partially hedged to any changes by way of your ethanol and biodiesel operations.

But it seems like any reallocation of volumes lost as more refinery exemptions would kind of come back on you as a larger operator.

So I was hoping you could give some context to those changes politically.

All right.

Jason's on.

This is Jason.

On October 15, the EPA released their supplemental RVO asking for public comment on -- including in the formula of the prior 3 years average of SREs, but the DOE recommended it to be granted.

I know that's a lot of words there.

That would be about 580 million gallons or 770 million gallons, depending on which prior 3 years you use, and they asked for comments on both.

So -- and then these obligations would be reobligated on the other non-exempt refineries in addition to your normal shares.

You get what you'd already get, and then you get this on top.

So our industry and many members of Congress have been clear that reallocating the SREs onto the other obligated parties like this is unworkable, and we view this as a violation of fundamental fairness.

To those of us who're already bearing our burden under the program, it may also be illegal.

So it's especially frustrating because it's been shown time and again by the EIA's own data.

They're granting these SREs in the past, and they've done it with no reallocations, as they have no negative effect on ethanol blending on actual liquid volumes they got moved.

But this is simply no real ethanol demand destruction.

So the reallocation he was asking about, the impact of the reallocation on us so the SREs, it obviously is going to cost more for us to comply with a larger volume obligation.

It's not -- I wouldn't call it material, but if there was $0.01, we wouldn't like it.

Anyway, we're going to do what we can to help deal with this.

Okay, great.

That's very helpful.

My second question is kind of a more detailed question back on the Diamond Green Diesel segment.

It appears that in the third quarter, sales volume came in pretty low.

And in order to meet that 750,000 gallon a day full year target, it seems like the fourth quarter will have to step up pretty materially.

Is there any context can give around why that might be the case?

We had guidance for the full year of 750,000, and we still expect to make that.

We expect a strong fourth quarter.

We had a scheduled catalyst change in the third quarter, and that's why we guided to 750,000 gallons per day for the year to begin with.

So we feel pretty good about the numbers.

Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt.

I was hoping you could give a sense of how your 2020 turnaround schedule compares to 2019?

Matt, this is Lane.

We don't give any real forward guidance or turnaround schedule as a policy.

Okay.

And then West Coast cracks got off to a great start in Q4, have come down a little bit here.

How do your 2 California refineries run so far this quarter?

And would you expect to capture all of this upside?

Yes.

This is Lane again.

We run well, and we continue to run well.

We had one small blip on our San Francisco area refinery, but other than that, it wasn't that meaningful to the performance there, and they've been running pretty well through all this.

I'm showing no further questions in queue at this time.

I'd like to turn the call back to Mr. Bhullar for closing remarks.

Thanks, Liz.

We appreciate everyone joining us today.

Obviously, please feel free to reach out to the IR team if you have any further questions.

Thank you.

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

Thank you for participating.

You may now disconnect.