Valero Energy Corp (VLO) — Q3 2019 Earnings Call Transcript

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’ve 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, diesel cracks improved from the previous quarter. Heavy and medium sour crude oil discounts to Brent crude remain narrow. Its 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 value natural gas liquids and refinery olefins to a premium high octane outlet product. The Central Texas pipelines and terminals reduce secondary costs and extend our supply chain from the Gulf Coast to a growing inland market. Other strategic growth projects 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, resulting 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 focus on market expansion and margin improvement. During the third quarter, we returned $679 million to stockholders, reflecting 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 $2.1 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, catalyst, 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 non-cash 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 non-cash costs, such as depreciation and amortization. For 2019, we expect general and administrative 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. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.

Good morning. Thanks for taking the question. 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 the strength you see on the screen? Do you think it’s a function of just turnaround activity versus something that’s the beginning of a more sustainable IMO impact? And maybe it’s a 30,000-foot question here, how do you think IMO plays out versus sustainability and the depth of impact as we think about your model over the next couple of years?

Good morning, Neil. Okay. Gary, you want to...

Yes, Neil, I think the products cracks, it’s pretty difficult to determine how much of the strength 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. I mean the things I would point to, the diesel curve is just continued 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 that you would see some of these low-sulfur feedstock, the cat crackers being pulled out of the cats and put into the low-sulfur bunker market. If you look today, low-sulfur VGO is $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 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 traded as high as 95% of Brent earlier this year. This morning, it's trading at 61% of Brent. The forward curve on high sulfur fuel oil was backward indicating it’s going to get weaker as we go forward. 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, with Maya and WCS at approximately 11.50% discount to Brent today. And we’re seeing medium sours weakening as well. So 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.

Thank you. And then the follow-up question is around renewable diesel. Maybe Joe, can you just talk about how you see this part of the business fitting into your long-term strategy? And then how do you think about the gating factors for adding that capacity that you talked about in the call and anything around the blender’s tax credit? 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 can be an important part of the story going forward.

Yes, I mean you took a page out of Paul Cheng’s book here. You got first three questions there. I’ll speak about part of it, I’ll let Martin speak about part of it, and Jason might want to cover kind of the probabilities for the blender’s tax credit. But I mean strategically, we are a company that really makes motor fuels, and we’re a company that takes their environmental responsibility and sustainability very seriously. So when we look at the opportunities to produce products where there is 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. So it fits right down the middle of our fairway and so we feel very good about not only the returns but 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?

Sure, 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 to 2030 and is calling for a 20% greenhouse gas reduction in 2030. The recent elections in Canada suggest we’re probably going to see a national standard in Canada, too, along with developments in New York State. So we think the future demand for renewable diesel just looks very strong.

You want to talk about the blender’s tax credit?

Yes, this is Jason. I’ll give you an update on the blenders’ tax credit. As you all know, it expired at the end of 2017. Both Chambers of Congress have proposed legislation that would extend it. I think the Senate has proposed two years retroactively to 2018, and 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 Senate Finance Chairman, Grassley’s top priorities, and there’s really not a lot of opposition to it. However, this impeachment process is certainly interfering with the bipartisan cooperation that’s needed to get the package agreed to. So that’s what creates a little more uncertainty than there was before.

Hey Neil, one other point I think that we’d like to make on this. Martin can speak to why we aren’t doing like 200,000 barrels a day of this.

I think the constraints to look at is in the feedstock market and we’re confident we can source it, and we’re not worried about that any time soon. But that’s the ultimate constraint on this is the feedstock. The feedstock supply is tied to global GDP per person, which is increasing. So we feel good about being able to secure the feedstock. Our partnership with Darling, they are a global leader in this. They process 10% of the world’s meat byproducts, so we feel we’re in a good place on securing the feedstock.

Appreciate all the perspective.

Yes, thank you. Good morning.

Good morning, Roger.

Yes, 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 look better, I was just curious maybe going back to Neil’s question there on how much of this might be turnarounds versus what we’re actually seeing in terms of the 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 products inventory was 16 million barrels higher than where we were in 2018 at the same time period. Now over the last two months, we’ve had significant product growth such that – the last set of stats showed we were 19 million barrels lower than where we were in 2018. So in the 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. So if you break it down, we see good demand, vehicle miles traveled look good, and the tonnage index looks good. But there are certainly some factors that are supply driven as well. The shutdown of PES, some planned and unplanned refinery outages have helped poor product fundamentals. Moving forward, you look and gasoline is just a little above the five-year average range, and diesel is at the lower end of the five-year average range on apparent days of supply. Both gasoline and diesel are below the five-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-ups on that. We’ve obviously seen this issue in the tanker market, part of that is clearly related to IMO with ships going into 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 there would be any legitimate risk of tightness in product tanking markets that could impact your export story as we go forward?

Yes, Roger, I think for us, most of our exports are short-haul market. We’re primarily going to Mexico and South America, and freight rates actually gives us a competitive advantage for other people trying to get to those markets. So I don’t really see it as much of a risk to us.

All right, great. Thank you.

Hi guys. 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 sticking to the tried and tested marine gas oil, or would they actually be looking at the very low-sulfur fuel oil as a cheaper substitute in the initial stages of IMO?

Yes. We have a compliant blend that we are offering in the Corpus Christi market. We are also proceeding with the project where we’ll be able to have a low-sulfur blend in Pembroke. But we’ve also seen that there are a lot of challenges in being able to blend this 0.5 material, especially with many of the low-sulfur paraffinic crudes. I think there’s a good chance that initially, ships will run marine gas oil and 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 the initial stages?

Yes, it will. Moreover, we’re seeing blends with low-sulfur bunker material still contain a significant percentage of distillate in the blend. Even if they’re burning the low-sulfur bunker, we still anticipate 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 we are finally seeing sour discounts widen out. Should we think that in Q4 and going ahead, there will be a little bit of a switch back to medium and heavies, which would also solve some of the naphtha issues you had in Q2?

Yes. That’s exactly what we see. We set another record for light sweet crude processing in the third quarter. The economic signals were strongly in favor of light sweet crude. We’ve been saying that we are at 1.6 million barrels a day of overall capacity and we fully utilized that in the third quarter. However, with the widening of the quality discount, especially for heavy sour crude, we favor processing it and we’re starting to see medium sour crudes become economic as well.

Thank you for taking my questions and congrats on another good quarter.

Thanks, Manav. Take care.

Hey, good morning. 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 few 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. We have been doing some of it backing out high sulfur or heavy sour crude. We haven’t been running high sulfur fuel directly, but we’ve been running blend components that are going into the high sulfur fuel oil market. We’ve run some of those, and we expect to do more as we move forward.

Okay. And then second question, obviously there is a change to the Maya formula, but Maya has to be competitive regardless of what the formula is. I’m just curious how you think about how these heavy barrels on 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, and you have the medium sours. So how do you think about how these should all price relative to each other?

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

Okay, great. Thank you.

Thanks, Phil.

Good morning. Thanks for taking the question.

Good morning, Prashant.

Good morning, Joe. Following up on Phil’s question there, price on Maya and WCS is one factor and relatively how those are on top of each other. In market access, the barrels are moving down of the Gulf is another, as we look to Canada talking about rail above curtailment. We’re starting to see the end of the curtailment start to roll off a little bit. It looks like, could we get a more Brent barrels of Canadian into the Gulf Coast market? I just wanted to get a sense of what you’re seeing out there and maybe give us a sense of what you can get on sort of a firm versus delivered basis for barrels and how does that play any further into kind of that Maya versus U.S. dynamic pricing of the curve?

Yes. We’re in ongoing negotiations with several producers in Western Canada on delivered rail volume. We have our Lucas rail facility that feeds Port Arthur refinery and a lot of capacity to run heavy Canadian there. We anticipate as we move through the fourth quarter, you will see rail volumes ramp up as we anticipate we’ll buy those barrels delivered on something equivalent to the WCS or Maya equivalent in the Gulf.

Okay, great. And then other factor, another question is just a follow-up on the ethanol, that’s a smaller segment, but I just wanted to get a sense of how you see the next couple of quarters playing out? And when we 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 sign post that swings to the positive, because obviously that could be 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 showing inventories are too low, which is pressuring margins. Production is trending lower, and ethanol inventory now on the weekly data is 2.5 million barrels lower than this time last year. 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, as well as from year-round E15 sales. And then we expect, really the big thing we expect is a rebound in export growth due to favorable blend economics, just the economics of blending ethanol and these global renewable fuel mandates. So we still feel very constructive in the long-term and think that’s going to be around the corner.

All right, thank you very much for the time. Appreciate it.

Hey guys, good morning.

Hi, Paul.

I think I have two questions. One, maybe is for Gary, I think. Before we sit, Gary, you mentioned that you haven’t really fit the high sulfur down to the Coker. Is that something that you guys believe technically, given the way economic, you can do? And does it matter whether it’s a delayed Coker or as a forward Coker?

Hey Paul, it’s Lane. We’ve historically run quite a bit – what Gary was talking about was we run a lot of outside blend stocks that go into a 3.5% fuel oil, and we’ve always done that. It’s a part of the market that we feel we understand technically, maybe better than a lot of the people in the industry. One of the critical strategies going into this, towards IMO, is to make sure you keep the connectivity between these feedstocks and the heavy crudes, and we work really hard at doing that. There are technical challenges around defaulting and some other things, but we are very focused on increasing the amount of heavy sours that we run.

Lane, so you’re saying that you won the heavy sour, the crude, or you won the heavy sour we see, I’m sorry?

We do both, but your question was around resid and... So the earlier question was, are you running more fuel oil? We don’t really run fuel oil per se. What we run is we run the blend stocks that go into 3.5%. So as you see that as people unwind that as fuel, you’re going to see more of these components around the world become available. The key is understanding technically and fitting into our system, which we’re working very aggressively to do.

How about the second part of my question, whether that makes any difference that – whether it’s a fully Coker or delayed Coker on your ability to run those?

Not really.

Not really, okay. And 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, will it make sense to move part of the free cash to pay down debt to really draw down the debt to a much lower level at some point? We may get hit by recession, we don’t know when, but at some point in may?

Yes, it’s a good question, Paul. I will 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 is really nothing to tell, Paul...

Well, it’s very expensive. You’re right, our next maturity is in 2025 and to try to get that called early is expensive and uneconomical to us.

That’s it. Thank you.

Thanks, Paul.

Thank you and good morning everyone. Good morning, Joe.

How are you doing Doug?

How are you Doug?

I should probably thank Paul for making room for the rest of us, so I thank him as well. I just go two quick questions, Joe. Obviously, IMO is the focus for the whole market right now. My question really is more about this year perspective on the duration of any perceived benefit. To give it, to explain my question, our view is that the industry can react to the product side with things like your VGO reallocation and things of that nature. The stickier side of it seems to be on the sour feedstock. So I just want to get your perspective as do you think that the product side of it is more sticky as well? In which case, what does it mean for gasoline balance, given what you described in your prepared remarks about VGO? Maybe explain your experience of what you’ve done with VGO and how you expect to operate going forward? And I’ve got a quick follow-up please.

Okay. Gary and Lane can speak to this. You know, Paul, I mean, Doug, excuse me, if you recall 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 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 want to speak to it in general and then…

Yes, I’ll start and then of course, Gary can always tune it up a little bit later here. We’ve played this out the way that we thought, and I think ultimately early on, you’re going to have this demand for diesel. It will be interesting to see how long that goes. I mean, it could go on for quite some time depending on the technical difficulty of making those fuels. We have seen some of that, as Gary alluded to it. It is not an easy task to create to make all the fuels work from a compatibility perspective. However, longer term, making a home for the 3.5% weight fuel oil is a much more capital-intensive thing to work through. Somebody alluded – was asking the question earlier about valuations of crude. What will be interesting is, right now, these crudes are valued not based on an open market but rather on 3.5% weight. You could see this disconnect even get greater. I don't know that we know you can think of all the paths to try to close that gap, but it all takes quite a bit of capital.

Yes, I think there’s a lot of uncertainty. We certainly anticipated you’d see scrubbers coming online, but it appears there are a lot of technical issues around the scrubbers that may prevent them from coming on as fast as we thought. The other area here with uncertainty is, when do some of this production that’s offline, some of these medium and heavy sour crudes, come back on the market? It’s very difficult to give you a timeline.

But it’s not a problem that’s going to be resolved very quickly. I think, again we’ve always kind of played down the product side of this, but I think we’ve expected more on the feedstock side. We’re seeing it in both right now, but this is going to take a while to solve.

Thanks for attempting to answer guys. I know it’s a really tough one, but incredibly 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, reliability, in terms of markets. You know the 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? I know you’ve always been pretty sensitive to buying back stock. When you get some kind of periodic strengthening in margins and obviously, 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, thanks.

Yes, I’ll let Donna talk to this. Because – I mean Doug, obviously there is not a formulaic approach to how you do this, right? I mean, you’re going to have your outlook for the market going forward. Obviously, we felt it has been pretty good, that’s why we’ve had significant dividend increases. We have had – and you want to be competitive from a yield perspective, not only with your peers but with the broader market. All those things taken into consideration, but not as far as the mix...

Yes, we do view the dividend as an important part of the total shareholder return, but it’s also important to us that it be sustainable. So we want it to be very competitive in the market generally and specifically against our peers. However, we also want to be able to sustain that dividend through the earnings cycle. So we always continue to look at that mix. 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. We haven’t altered our approach, and when 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.

Would we expect the buyback to slow if you did – let’s say, you were 20% higher, would you still be buying back your shares?

If we were 20% higher, it all goes to...

As you know, it’s a cyclical business obviously. So you buy back. You know at some point it’s going to drop again probably, so I guess, how do you respond to continue strengthening?

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 target and you work to achieve it and that gives you consistency, not only with what the financial markets expect from you, but operationally what you can afford to invest in and how you can grow the business. That’s why we said 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 any forecast dividend increases, at all, we just rely on the fact that we told you what we’re going to do, and we’re going to do it.

Great answer. Thanks Joe. Appreciate it.

You bet.

Good morning, everybody, hi.

Hi, Sam.

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 comment around feedstock constraints, can you just talk a little bit about why that location is a good one? It seems like you operate in places that might have more local biomass. Are you importing or is it the marketing thing or are you exporting? I’m asking because as this business scales, it would be good to know just sort of the factors that you look at for performance.

Yes, this is Martin. The thing that helps renewable diesel is being co-located with the refinery. So that’s probably the primary thing we’re looking at, and in a place where we can hit all the markets. 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, thanks. So it’s a combination of placement and feedstock, thanks. That’s helpful. And then, we’re like six weeks since the uptake 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 to 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?

Yes, 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 Kuwaiti barrels, which have been primarily due to the West Coast, which has been unaffected. But we don’t see any Saudi volume coming into our system at all.

All right. Thanks so much.

Hi, everyone. 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 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 that I’m not thinking of?

Yes, Brad. I think you 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, that’s an optimization for us and it is a demand pull, and with the large light product inventory draws we saw in the U.S., we had a better net back 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 phenomenal number was $1.1 billion. When I think back a couple of years ago, it used to be in the 900s or even the high 800 sometimes. Is there any underlying factor that’s driven at higher OpEx number?

It’s easier for me to sort of compare it to year-over-year by the way rigs. Our volumes were down in the third quarter, largely we had three external power failures, and then we had the storm deal with that went through and affected our Port Arthur operations. Our volumes weren’t as high as they were with these, part of that is just on a per-barrel basis, it’s a little bit higher, and then some other factors. We’ve changed what is in and out of our operations, and 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 have occurred over time as well.

Okay, nothing structural?

No, nothing structural.

Thank you.

Yes, hi, thanks for taking the questions. I wanted to follow-up on something Roger Read asked around the higher shipping rates. Obviously, there are 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 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 in higher blended feedstock costs? Thanks.

Sure. I’ll start on the feedstock side. Obviously with the – we’ve been running, we’re running a lot of pipeline delivered crude and then a lot of the barrels that we’re getting over the water are short-haul barrels. So we don’t see a big impact on our feedstock costs and similarly on the products, the barrels going into the domestic markets, or 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 been positive to the business, as freight rates have spiked, Joe mentioned in his opening comments that the Brent TI spread had come in with the pipeline capacity coming online. With the freight rates spiking we’ve seen Brent TI blow back out some and back over $5, which gives U.S. refining a significant advantage on running light sweet crude. Also, as I mentioned previously into our export location, when you’re going to Mexico, the higher freight rates give us a competitive advantage over some of our global refining competitors trying to import to those markets.

All right, thanks for that. I appreciate that color. And then if I could ask just on the Syncrude marketing kind of the northern crude market, because I know you guys run a decent amount into Quebec. It seems like there are going to be some changes in the balances in terms of an operator maybe using less Syncrude for diluent and then the Northwest refinery 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 spend through line nine and I think our view would probably see – we see a little bit more Bakken than we see syn going to Quebec as we move forward in an IMO environment.

All right, thanks a lot.

Thanks, Jason.

Good morning, thanks for taking the question. 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 bio-diesel operations, but it seems like any reallocation of volumes lost to small refinery exemptions would come back on you as larger operators? I was hoping you could give some context to those changes politically?

All right. Jason is on.

Yes, hi, this is Jason. You’re right. On October 15th, the EPA released their supplemental RVO asking for public comment on, included in the formula, the prior three years average of SREs, but the DOE recommended be granted. To put it simply, that’d be about 580 million gallons or 770 million gallons. They asked for comments on both. These obligations will be reobligated on the non-exempt refiners in addition to your normal share. You should get what you already get, and then you get this on top. Our industry and many members of Congress have been clear that reallocating SREs on the other obligated parties like this is unworkable, and we view it as a violation of fundamental fairness to those of us who already bear the burden of the program. It has been shown time and again by the EIA using data that granting these SREs in the past, as they’ve done with no reallocation, has had no negative effect on ethanol blending in terms of actual liquid volume, but this shows no real ethanol demand destruction.

So the reallocation, he was asking about the impact of the reallocation on us, so the SREs, I mean 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 it 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. Thank you. 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 gallons a day full-year target, it seems like the fourth quarter will have to step up pretty materially. Is there any context you 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 the 750,000 gallons per day for the year to begin with. So we feel pretty good about the numbers.

Okay, great. Thank you.

Thanks, Patrick.

Hey, good morning everyone. I was hoping you could give a sense of how your 2020 turnaround schedule compares to 2019?

Hi, Matthew. This is Lane Riggs. We don’t give any real forward guidance to our turnaround schedule at this point.

Okay. And then West Coast cracks got off to a great start in Q4; they have come down a little bit here. How have your two California refineries run so far this quarter, and would you expect to capture all this upside?

Yes, this is Lane again. We’ve run pretty 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 around; they’ve been running pretty well through all this.

Sounds good. Thanks.

Thanks guys. 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.