Ladies and gentlemen, thank you for standing by, and welcome to Valero Energy Corporation's Third Quarter 2019 Earnings Conference Call. At this time, all participant lines are in a listen only mode. After the speakers' presentation, there will be a question and answer Please be advised that today's conference may be recorded. I'd now like to hand the conference over to your speaker today, Mr. Homer Buller, Vice President, Investor Relations.
Please go ahead, sir.
Good morning, everyone, and welcome to Valero Energy Corporation's Q3 2019 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer Donna Tietzman, 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 1 on our website atvalero.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 remain 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 $1,400,000,000 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 alkalate product. And the Central Texas pipelines and terminals reduce secondary costs and extends our supply chain from the Gulf Coast to a growing inland market. Other strategic growth projects and 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 Fort 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 1,100,000,000 gallons annually. The guiding framework underpinning our capital allocation strategy remains unchanged.
We continue to expect our annual CapEx for both 2019 2020 to be approximately $2,500,000,000 with $1,000,000,000 allocated for projects with high returns that are focused on market expansion and margin improvement. During the 3rd quarter, we returned $679,000,000 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. 4th 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 Q3 of 2019, net income attributable to Valero stockholders was $609,000,000 or $1.48 per share compared to $856,000,000 or $2.01 per share in the Q3 of 2018. Operating income for the refining segment in the Q3 of 2019 was 2018 is mainly attributed to narrower crude oil discounts to Brent Crude Oil. Refining throughput volumes averaged 2,950,000 barrels per day, which was 146,000 barrels per day lower than the Q3 of 2018. Throughput capacity utilization was 94% in the Q3 of 2019.
Refining cash operating expenses of $4.05 per barrel were $0.33 per barrel higher than the Q3 of 2018, primarily due to higher maintenance activity and lower throughput in the Q3 of 2019. The ethanol segment generated a $43,000,000 operating loss in the Q3 of 2019 compared to $21,000,000 in operating income in the Q3 of 2018. The decrease from the Q3 of 2018 was primarily due to lower margins resulting from higher corn prices. Ethanol production volumes averaged 4,000,000 gallons per day in the Q3 of 2019. Operating income for the renewable diesel segment was $65,000,000 compared to a $5,000,000 operating loss in the Q3 of 2018.
Renewable diesel sales volumes averaged 638,000 gallons per day in the Q3 of 2019, an increase of 387,000 gallons per day versus the Q3 of 2018. The Q3 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 Q3 of 2019, general and administrative expenses were 217 $17,000,000 and net interest expense was $111,000,000 Depreciation and amortization expense was 5 67,000,000 and income tax expense was 165,000,000 in the Q3 of 2019. The effective tax rate was 21%. With respect to our balance sheet at quarter end, total debt was $9,600,000,000 and cash and cash equivalents were $2,100,000,000 Valero's debt to capitalization ratio net of $2,000,000,000 in cash was 26%.
At the end of September, we had $5,400,000,000 of available liquidity excluding cash. With regard to investing activities, we made $525,000,000 of capital investments in the Q3 of 2019, of which approximately $305,000,000 was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance. Net cash provided by operating activities was $1,400,000,000 in the 3rd quarter. Excluding the impact from the change in working capital during the quarter, adjusted net cash provided by operating activities was 1,100,000,000 dollars Moving to financing activities, we returned $679,000,000 to our stockholders in the 3rd quarter. $372,000,000 was paid as dividends with the balance used to purchase 3,900,000 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 $1,700,000,000 and the total payout ratio to 54% of adjusted net cash provided by operating activities. As of September 30, we had approximately $1,700,000,000 of share repurchase authorization remaining. We continue to expect annual capital investments for both 2019 2020 to be approximately $2,500,000,000 with approximately 60% allocated to sustaining the business and approximately 40% to growth. The $2,500,000,000 includes expenditures for turnarounds, catalysts and joint venture investments.
For modeling our 4th quarter operations, we expect refining throughput volumes to fall within the following ranges: U. S. Gulf Coast at 1,710,000 to 1,760,000 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 4th quarter to be approximately $3.95
per barrel.
Our ethanol segment is expected to produce a total of 4,300,000 gallons per day in the Q4. 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 19, we expect G and A expenses excluding corporate depreciation to be approximately 840,000,000 dollars The annual effective tax rate is estimated at 22%.
For the 4th quarter, net interest expense should be about $113,000,000 and total depreciation and amortization expense should be approximately $565,000,000 dollars Lastly, we still expect the RINs expense for the year to remain between $300,000,000 $400,000,000 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 and A to 2 questions. If you have more than 2 questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.
Your first question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open.
Good morning. Thanks for taking the question. Let me start off with the obligatory IMO 20 20 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 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, both the 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 product 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. Things I would point to, the diesel curve has 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 feedstocks, 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, 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 backward indicating it's going to get weaker as we go forward. And as you would expect, as high sulfur fuel has traded weaker, we're starting to see that in the crude quality discounts.
So through most of the year, we 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.
Thank you. And then the follow-up question is around renewable diesel and maybe Joe and team, you could 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 new capacity that you talked about in the call and then anything around blenders 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's going to be an important part of the story, Gordon.
Yes. I mean, Neal, you took a book out of Paul Cheng, a page out of Paul Cheng's
book here.
You got those 3 questions
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 blenders 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, 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?
Sure, Joe. Thanks. Yes, we're bullish on renewable diesel. We expect demand growth to be strong. You've got the renewable energy directive 2 in Europe now that's been extended to 2,030.
The California LCFS has been extended out to 2,030 and calling for a 20% greenhouse gas reduction in 2,030. 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.
You want to talk about the Blenders tax credit?
Yes, this is Jason. I can 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's got it going out for 2 years and this is back retroactive to 2018. In the House for 3 and negotiations on the BTC and the 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 you need to get the package agreed to. So that's what's created a little more uncertainty than there was before.
One other point I think that we'd like to make on this and Mark can speak to why isn't why aren't we doing like 200,000 barrels a day of this.
Yes, I think the constraints you look at is in the white feedstock market. Now 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 of these 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 byproducts.
So we feel we're in a good place on securing the feedstock.
Appreciate all the perspective.
Our next question comes from Roger Read with Wells Fargo. Your line is now open. Yes.
Thank you. Good morning.
Good morning, Roger.
Just 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 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 products inventory was 16,000,000 barrels above where we were in 2018 at the same time period. And over the last 2 months, we've had significant product draws such that the last set of stats, we were 19,000,000 barrels below 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 life product 35,000,000 barrels, which is a pretty staggering figure. And so if you look at that, break it down, we see good demand, vehicle model travel look good, the tonnage index looks good. But then there's certainly some things that are supply driven as well, shutdown of PES, some planned and unplanned refinery outages have driven that as well and helped support product fundamentals.
But moving forward, you look in gasoline 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 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 as kind of a follow-up on that, we've obviously seen this issue in 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. So Roger, I think for us most of our exports are short haul markets. So we're primarily going to Mexico and South America and 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.
All right, great. Thank you.
Our next question comes from the line of Manav Gupta with Credit Suisse. Your line is now open.
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 with sticking to the tried and tested marine gas oil or would they actually be looking at very low sulfur fuel oil 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 the projects 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 the initial stages?
Yes, it will. And I think even with the blends we're seeing on the low sulfur bunker material, those ones still contain a fairly significant percentage of distillate in the blend. And so even if they're burning the low sulfur bunker, we 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 70000, 70,000 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 4Q and going ahead, there's 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 Q3. The economic signals were strongly in favor of light sweet crude. We've been saying that again, we've got 1,600,000 barrels a day of overall capacity and we pretty much fully utilized that in the Q3.
But certainly with the widening of the quality discounts, especially the heavy sour crude are favored 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. Thank you.
Thanks, Vedav. Take care.
Our next question comes from Phil Gresh with JPMorgan. Your line is now open.
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 Hyso for fuel oil as a feedstock? I think residuals have been about 200,000 barrels a day or so each of the past two 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. 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 think about how these heavy barrels on the Gulf Coast need the 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 sour. So how do you think about how these 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.
Okay, great. Thank you.
Thanks, Phil.
Our next question comes from Prashant Rao with Citigroup. Your line is now open.
Good morning. Thanks for taking the question.
Good morning, John.
Good morning, Joe. After following up on Phil's question there, price online and WCS is one factor and sort of relatively how those are on top of each other. But in market access and barrels that are moving down to the Gulf is another. As we look into Canada is talking about rail above curtailment, we're starting to see curtailment, NDA curtailment start to roll off a little bit. It looks like it could be getting more Brent barrels of Canadian into the Gulf Coast market.
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 in further into kind of that Maya versus CS dynamic 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 Q4 you'll see rail volumes ramp up and
And we anticipate
as we move to the Q4, you'll see rail volumes ramp up as and we anticipate we'll buy those barrels delivered on something equivalent to the WCS or MayaQuote 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 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 signpost that, that swings to the positive? Because obviously, there could be incremental upside there too in the quarters ahead if factors play out right.
This is Martin. I think near term October is looking a lot better than the Q3 did. What you've seen is the recent DOE data. What the issue has been is oversupply in the U. S, right?
Inventory is just too low, which is pressuring margins. The production is trending lower. Ethanol inventory now on the weekly data is 2,500,000 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 that 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. 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.
Our next question comes from Paul Cheng with Scotia Howard Weil. Your line is now open.
Hey, guys. Good morning. Hi Paul. I think I had two questions. One maybe is for Kevin.
I will try to stick to just 2, not more. That for we sit Gary, you mentioned that you haven't really fit the high sulfur we sit directly to the coker. Is that something that you guys believe technically, given the right economic you can do? And does it matter whether it's a delayed coker or it's a full rate coker?
Hi, Paul. It's Alain. I'll talk to we've historically ran quite what Gary was talking about was we run a lot of, I would say, blend stocks that go in a 3.5 weight percent fuel oil. We've always done that and we it's a 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 strategies going into this towards going into IMO is to make sure you keep connectivity between these feedstocks and the heavy crews and we've worked really hard at doing that.
There are technical challenges, they are around defaulting and some of the other things, but we are very focused on increasing the amount of heavy sour reserves that we run.
So Ning, so you're saying that you run the heavy sour, the crew or you run the heavy sour, we sit, I'm sorry?
We do both, but your question was around resid. And what was so 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 into 3.5 weight percent. And so as you see that as people unwind that as a fuel, you're going to see more of these components around the world become available. And the key is going out there and understanding
separate c whether it's a full weight coker or delayed coker in your ability to 1 dose?
Not really.
Not really? Okay. And that, 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 drive 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.
That'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
can offer. Well, it's very expensive, you're right. Our next maturity is in 2025 and to try to get that called early would be expensive and uneconomical to us.
I see. Thank you.
Thanks, Tom.
Our next question comes from Doug Leggate with Bank of America. Your line is now open.
Thank you. Good morning, everyone. Good morning, Joe.
How are you, Doug?
I should probably thank Paul for making room for the rest of us. So I thank him as well. So I just got 2 quick questions, Joe. Obviously, IMO is the focus for the whole market right now. And my question is really more about just your perspective on duration of any perceived benefit.
To give it to explain my question a little further, our view is that the industry can react to the product side of it with things like your VGO reallocation, 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 that 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 it to operate going forward?
And I've got a quick follow-up, please.
Okay. 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 want to just speak to it in general and then?
Yes, so I'll start and then course, Gary can always tune me up a little bit later here. But we as Joe alluded to, this is we've all 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 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 Jim making those fuels.
And we have seen some of that like Gary alluded to it. It 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 and making that and not having a home for it is a much more capital intensive thing to try to work through. And somebody alluded to was asking a question earlier about valuations of crude. What will be interesting is, right now, I would say these crudes are to the extent that heavy sour and medium sour are running not they're not being valued based on an open coffeur, but they're being valued based on 3.5 weight percent.
You could see it you're going to see that disconnect even get greater. And I don't know that we know you can think about all the past 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 come online, but it appears there's a lot of technical with
uncertainty
with uncertainty is when does some of this production that's offline, some of these medium and heavy sour crudes, when do they come back on the market. So very difficult to give you a timeline.
But 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.
Thanks for attempting to answer, guys. 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, Joe?
I know you've always been pretty sensitive to buying back stock when you get these 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. 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've had the 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. So all those things get taken into consideration, but not 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 be 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 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. And we haven't altered our approach. And we say we look at ratability plus, we look at buying on dips. And frankly we had a situation where looking into a strong Q4 with the prospects for IMO.
Said, it's a good time to buy back more shares. And so that's what we did in the Q3. So we took advantage of an opportunity and we'll do that going forward.
Would we expect the buyback to slow if you did? Because let's say you were 20% higher, would you still be buying back your shares?
If we were 20% higher, It all goes
to This
is a because you know it's a cyclical business obviously. So you buy back, you know that 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 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, but just rely on the fact that we had told you what we're going to do and we're going to do it.
Great answer. Thanks, Joe. Appreciate it.
You bet.
Our next question comes from Sam Margolin with Wolfe Research. Your line is now open.
Good morning, everybody. Hi.
Hi, Sam.
I have a follow-up on renewable diesel actually. 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 a marketing thing where you're exporting?
I'm asking because as this business scales, it'd be good to know just sort of the factors that you look at for performance.
Yes. This is Martin. I mean, the thing that helps renewable diesel is being co located with the refinery. 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 to the United States just because of the feedstock supply in the U. S. 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 6 weeks since the Avtec stabilizer went down in Saudi. People who count the ships coming out of the Gulf Sea stable exports.
But can you talk a little bit about what you're seeing as far as high sulfur or 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 Kuwait primarily 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.
Our next question comes from Brad Heffern with RBC. Your line is now open.
Hey, everyone. A question on exports. So when I was looking at the numbers for last year for the Q3, I think you guys exported over 400,000 barrels a day. This year was just a little over 300,000 barrels a day. Is that demand pull into the U.
S? Is that export weakness? Or is there some other factor there 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 from the dock there, which didn't limit us a little bit. But the big driver was what you pointed to. That's an optimization for us and it is demand full. And with the large light product inventory draws we saw in 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 a nominal number was $1,100,000,000 When I think back a couple of years ago, it used to be in the 900s or even the high 800s sometimes. Is there any underlying factor that's driven that higher OpEx number?
It's easier for me to sort of compare it to year over year by the way, Lane Riggs. And our volumes were down in the Q3 largely. We had 3 external power failures and we had the storm deal with it went through and affected our core operations. So our volumes weren't as high as they were these 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 occurred over time as well.
Okay. But nothing structural?
No, nothing structural.
Thanks.
Our next question comes from Jason Gabelman with Cowen. Your line is now open.
Yes. Hey, 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 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 higher landed feedstock costs?
Thanks.
Sure. I'll start on the feedstock side. Obviously with the diet 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 are 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 been positive to the business, straight raises spiked. Joe mentioned in his opening comments that the rent 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 U.
S. Refining a significant advantage on running light sweet crude. And as I mentioned previously into our export location, 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. Thanks for that. I appreciate that color. And then if I could ask just on the Syncrude market and kind of 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 an operator maybe using less Syncrude 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 price crude. So we have a lot of optimization opportunities on what we spend through Line 9. And I think our view would probably see, we see a little bit more Bakken than we see Cin going to Quebec as we move forward in an IMO environment.
All right. Thanks a lot.
Thanks, Jason.
Our next question comes from Patrick Blem with Simmons Energy. Your line is now open.
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 biodiesel operations. It seems like any reallocation of volumes lost to small 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 is on. Sure. Yes. Hi, this is Jason.
You're right. On EPA released their supplemental RVO asking for public comment on including in the formula the prior 3 years average of SREs that the DOE recommended be granted. I know it's a lot of words there. That'd be about 580,000,000 gallons or 770,000,000 gallons depending on which prior 3 years you use and they asked for comments on both. So and then these obligations will be re obligated on the other non exempt refiners 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 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 are already bearing our burden under the program and it may also be legal. So and it's especially frustrating because it's been shown time and again by the EIA zone data that granting this SREs in the past as they've done it with no reallocation has had no negative effect on ethanol blending on actual liquid volume that 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, on 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. So 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 Q3 sales volume came in pretty low.
And in order to meet that 750,000 gallon a day full year target, it seems like the Q4 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 $750,000,000 and we still expect to make that. We expect a strong Q4. We had a scheduled catalyst change in the Q3 and that's why we've guided to 750,000 gallons a day for the year to begin with. So we feel pretty good about the numbers.
Okay, great. Thank you.
Thanks, Patrick.
Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Your line is
now open.
Hey, good morning, everyone.
Good morning, Paul. Thanks. I was
hoping you could give a sense of how your 2020 turnaround schedule compares to 2019?
Hi, Matthew. This is Leonard. We don't give any real forward guidance to our turnaround schedule of Apollo 2.
Okay. And then West Coast Cracks got off to a great start in Q4, come down a little bit here. How have your 2 California refineries run so far this quarter? And would you expect to capture all of this upside?
Yes. This is Lane again. So we ran pretty we ran well and then 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 they're in. They've been running pretty well through all this.
Sounds good. Thanks.
I'm
showing no further questions in queue at this time. I'd like to turn the call back to Mr. Boehler 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.