瓦萊羅能源 (VLO) 2019 Q4 法說會逐字稿

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

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

(Operator Instructions) I would now like to hand the conference over to your speaker today, Homer Bhullar.

Thank you.

Please go ahead, sir.

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

With me today are Joe Gorder, our Chairman and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our President and COO, Jason Fraser, our Executive Vice President and General Counsel; Gary Simmons, our Executive Vice President and Chief Commercial Officer; 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 are pleased to report that we had a good quarter, delivering solid financial results.

Our refineries operated well at 96% utilization, allowing us to take advantage of wider sour crude oil differentials and weakness in high sulfur residual feedstocks.

Overall, 2019 was a challenging environment for the refining business.

We started the year with gasoline inventories at record high and gasoline cracks at historic lows.

We were also faced with narrow sour crude oil differentials for most of the year, primarily due to sanctions on Venezuela and Iran, in addition to OPEC and Canadian crude oil production curtailments.

And differentials on inland sweet crude oils narrowed in the second half of the year with the start-up of multiple new crude pipelines from the Permian Basin to the Gulf Coast.

Despite this challenging backdrop, our team demonstrated the strength of our assets and prior investments to improve our feedstock and product flexibility, allowing us to deliver another year of steady earnings and free cash flow.

We demonstrated our crude supply flexibility by processing an annual record of 1.4 million barrels per day of North American sweet crude oil as well as a record of approximately 180,000 barrels per day of Canadian heavy crude oil in 2019.

We also achieved another milestone by delivering the best ever year on employee safety performance and the lowest number of environmental events in company history, demonstrating our strong commitment to safety, reliability and environmental stewardship.

We continue to invest in projects that enhance the flexibility and margin capability of our portfolio.

In 2019, we successfully started up the Houston Alkylation Unit and completed the Central Texas pipeline and terminals project.

And we have several growth projects that will be completed this year, including the Pasadena terminal, St.

Charles alkylation unit and the Pembroke cogeneration unit.

Looking further out, the Diamond Pipeline expansion should be completed in 2021 and the Diamond Green Diesel and the Port Arthur Coker projects are still on track to be completed in 2021 and 2022, respectively.

We also continue to explore growth opportunities in our renewable fuels business, which is already the largest in North America.

As we previously announced, the Diamond Green Diesel joint venture is in the advanced engineering review phase for a new renewable diesel plant at our Port Arthur, Texas facility.

If the project is approved, operations are expected to commence in 2024, which will result in Diamond Green Diesel's renewable fuels production capacity increasing to over 1.1 billion gallons annually or over 70,000 barrels per day.

We remain disciplined in our allocation of capital, a constant in our strategy for several years, which prioritizes our investment-grade credit rating, sustaining investments and maintaining a sustainable and growing dividend.

We expect our annual CapEx for 2020 to be approximately $2.5 billion, which is consistent with our average annual spend over the last 6 years, with approximately $1 billion allocated for high-return growth projects that are focused on market expansion and margin improvement and the balance allocated to maintain safe, reliable and environmentally responsible operations.

And you should continue to expect incremental discretionary cash flow to compete with other discretionary uses, including organic growth investments, M&A and cash returns to our investors.

Looking ahead, we have a favorable outlook for refining margins with the IMO 2020 low sulfur fuel oil regulation, which just took effect on January 1st.

High sulfur crude oils are expected to be more discounted due to lower demand as less complex refineries switched to sweeter crude oils.

Valero's complex refining system is well positioned to take advantage of the discounted high sulfur crudes and fuel oils as feedstocks.

And our growing renewable diesel segment continues to generate strong results due to the high demand for renewable fuels.

In closing, our incredible team's relentless focus on operational excellence, a steady pipeline of high-return organic growth projects and a demonstrated commitment to shareholder returns should continue to position Valero well.

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

Thanks, Joe.

For the fourth quarter of 2019, net income attributable to Valero stockholders was $1.1 billion or $2.58 per share compared to $952 million or $2.24 per share in the fourth quarter of 2018.

Fourth quarter 2019 adjusted net income attributable to Valero stockholders was $873 million or $2.13 per share compared to $932 million or $2.19 per share for the fourth quarter of 2018.

For 2019, net income attributable to Valero stockholders was $2.4 billion or $5.84 per share compared to $3.1 billion or $7.29 per share in 2018.

2019 adjusted net income attributable to Valero stockholders was $2.4 billion or $5.70 per share compared to $3.2 billion or $7.55 per share in 2018.

The 2018 and 2019 adjusted results exclude several items reflected in the financial tables that accompany the earnings release.

For reconciliations of actual to adjusted amounts, please refer to those financial tables.

Operating income for the refining segment in the fourth quarter of 2019 was $1.4 billion compared to $1.5 billion for the fourth quarter of 2018.

Refining throughput volumes averaged 3 million barrels per day, which was in line with the fourth quarter of 2018.

Throughput capacity utilization was 96% in the fourth quarter of 2019.

Refining cash operating expenses of $3.93 per barrel were in line with the fourth quarter of 2018.

The ethanol segment generated $36 million of operating income in the fourth quarter of 2019 compared to a $27 million operating loss in the fourth quarter of 2018.

The increase from the fourth quarter of 2018 was primarily due to higher margins resulting from higher ethanol prices.

Ethanol production volumes averaged 4.3 million gallons per day in the fourth quarter of 2019.

Operating income for the renewable diesel segment was $541 million in the fourth quarter of 2019 compared to $101 million for the fourth quarter of 2018.

After adjusting for the retroactive Blender's Tax Credit recorded in the fourth quarter of 2019, adjusted renewable diesel operating income was $187 million in the fourth quarter of 2019 compared to $167 million for the fourth quarter of 2018.

The increase in operating income was primarily due to higher sales volume.

Renewable diesel sales volumes averaged 844,000 gallons per day in the fourth quarter of 2019, an increase of 124,000 gallons per day versus the fourth quarter of 2018.

For the fourth quarter of 2019, general and administrative expenses were $243 million and net interest expense was $119 million.

General and administrative expenses for 2019 of $868 million were lower than 2018, mainly due to adjustments to our environmental liabilities in 2018.

For the fourth quarter of 2019, depreciation and amortization expense was $571 million and income tax expense was $326 million.

The effective tax rate was 20% for 2019.

Net cash provided by operating activities was $1.7 billion in the fourth quarter of 2019.

Excluding the unfavorable impact from the changes in working capital of $434 million and our joint venture partner's 50% share of Diamond Green Diesel's net cash provided by operating activities, excluding changing in its working capital, adjusted net cash provided by operating activities was $1.9 billion.

With regard to investing activities, we made $722 million of capital investments in the fourth quarter of 2019, of which approximately $445 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance.

For 2019, we invested $2.7 billion, which includes all of Diamond Green Diesel's capital investments of $160 million.

Excluding our partner's 50% share of Diamond Green Diesel's capital investments, Valero's capital investments for 2019 were approximately $2.6 billion, with approximately $1 billion of the total for growing the business.

Moving to financing activities.

We returned $591 million to our stockholders in the fourth quarter.

$369 million was paid as dividends with the balance used to purchase 2.3 million shares of Valero common stock.

This brings our 2019 return to stockholders to $2.3 billion, and the total payout ratio to 47% of adjusted net cash provided by operating activities.

As of December 31, we had approximately $1.5 billion of share repurchase authorization remaining.

And last week, our Board of Directors approved a 9% increase in the regular quarterly dividend to $0.98 per share or $3.92 per share annually, further demonstrating our commitment to return cash to our investors.

With respect to our balance sheet at quarter end, total debt was $9.7 billion and cash and cash equivalents were $2.6 billion.

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

At the end of December, we had $5.3 billion of available liquidity, excluding cash.

Turning to guidance.

We continue to expect annual capital investments for 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 first quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.63 million to 1.68 million barrels per day, U.S. mid-continent at 410,000 to 430,000 barrels per day, U.S. West Coast at 230,000 to 250,000 barrels per day, and North Atlantic at 470,000 to 490,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be approximately $4.15 per barrel.

Our ethanol segment is expected to produce a total of 4.2 million gallons per day in the first quarter.

Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization.

With respect to renewable diesel segment, we expect sales volumes to be 750,000 gallons per day in 2020.

Operating expenses in 2020 should be $0.50 per gallon which includes $0.20 per gallon for noncash costs such as depreciation and amortization.

For the first quarter, net interest expense should be about $113 million and total depreciation and amortization expense should be approximately $560 million.

For 2020, we expect G&A expenses, excluding corporate depreciation, to be approximately $860 million.

The annual effective tax rate is estimated at 22%.

Lastly, we expect RINs expense for the year to be 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 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.

(Operator Instructions) And our first question comes from the line of Phil Gresh from JPMorgan.

So first question, 2-part question.

I was wondering if you could discuss in the fourth quarter, what incremental actions Valero took in order to run more fuel oil as a feedstock across the portfolio?

And how much of that you're actually able to capture in the quarter?

As well as why you think the high sulfur fuel oil prices have started to strengthen here in the beginning of 2020?

I'll start with -- in terms of how we maybe looked at our operating conditions and our operating envelope, and then Gary can sort of finish up with the market.

On the operating condition, we widened our window -- our operating window to try to reach out and get more challenging high sulfur resids.

We always -- we've, for years and years and years, really for the decade, we've been somebody who buys a lot of high sulfur resids to run and we opened up the market, went out and looked, we believe the idea was -- as the market changed and try to conform to IMO 2020 some of these high sulfur resids would free up in the marketplace.

And so we -- and we want to get the resid before it gets blended into the high sulfur fuel oil market because of quality reasons.

So that's really what we did.

We reached out and ran quite a few high sulfur resid that we have not historically ran.

Yes.

So the second part of that in terms of, I guess would how much of it showed up in the fourth quarter.

We ran a lot of high sulfur resids, but we really didn't see the discounted barrels coming in until about mid-December.

So it didn't have a real significant impact on fourth quarter results, and you'll see that more going forward.

But in terms of high sulfur fuel oil getting more expensive, it's -- we're still in the very early phase of what's a significant transition in our industry as we respond to the IMO bunker sulfur spec change.

And so with a change of this magnitude, you would expect it to create some volatility in the markets and it will take some time for the markets to reach equilibrium.

So we certainly see that there's not a lot of liquidity in the physical fuel oil markets, we -- there's a lot more liquidity in the paper markets.

If you look at the forward curve, it's steeply backwardated and kind of showing fuel oil gets back to 60%, 65% of Brent, which is kind of more where we think it will be.

So our view really in respect to high sulfur fuel oil and the crude oil quality discounts hasn't changed.

As the markets normalize, we expect to see the discount widen back out as the forward curve reflects, and as high sulfur fuel blend stocks have to compete for space with heavy sour crudes into complex refining capacity like we have in the Gulf Coast.

Okay, got it.

The second question, just on the capital allocation side of things.

You continue to keep capital spending flattish here in 2020, and you had a really healthy dividend increase that you just announced, which looks pretty well covered by cash flow.

So just curious how you're thinking about this increase in the dividend?

And is it just a shift from the dividend to the buyback and you're sticking with the same constructs that you've had, 40% to 50% of cash flow?

And obviously, the buyback will reduce the dividend burden over time, but just curious how you're thinking about this today.

No, we haven't changed our policy, and it continues to be that we want to return 40% to 50% of the cash flow from operations to the shareholders.

The dividend increase is just a part of that payout.

We don't have anything particular in mind in regards to the dividend only payout.

It's just part of the overall cash return.

You might see that dividend as a percentage of the total vary each year, as our cash flow varies, but buybacks will continue to fill in the balance of that return.

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

Joe, could you talk a little bit about the Gulf Coast operating results, you were almost up 75% on operating income on the Gulf Coast.

And the context I'm trying to understand this is like you have global majors, which indicated that downstream earnings could be down 80% quarter-over-quarter.

Another one reported today, downstream earnings down 36%.

How is Valero in an alternate universe where you are so much better than others?

Manav, that's a really good question, and I'd love to give you a intelligent answer, but why don't I get one of these guys to cover it here, Gary and Lane.

So Manav, I mean, first of all, we did see higher discounts, crude oil discounts and obviously the resids discount in the fourth quarter.

So if you're comparing third quarter to the fourth quarter, that's part of the answer.

The second part of the answer is, we got better naphtha netbacks because naphtha prices improved over the quarter.

And again, also it's butane, so butane -- when you compare fourth quarter to third quarter, it is our ability to run cheaper butane and at least blend it, obviously, helped us with our capture rates when compared to the third quarter.

A quick follow-up on the renewable diesel and the expansion of targeted for late 2021.

You guys have indicated a normalized margin of only 1.25 versus 1.80 or something realized in this quarter without BTC.

But if you put the basic even 1.25, you could get like $250 million EBITDA on the base margin and then about another $140 million.

So you're looking at a return of like $390 million of EBITDA on this project.

So from your capital expenditure point of $550 million, it looks like a 2-year payback on this entire project?

Like is the math right or is something off here?

We feel pretty good about it Manav.

This is Martin Parrish.

We still feel good about the pro forma guidance of the $1.26 as it excludes the Blender's Tax Credit.

So that puts you at $2.26 per gallon EBITDA.

I think that kind of checks out with what you're saying.

So Manav, you're very close.

Our next question comes from the line of Doug Leggate from Bank of America.

Joe, I got one on the market and one on Valero.

Let's go with the Valero first.

Maybe Donna wants to take this.

But Phil already asked about the 40%, 50% of your cash flow payout.

I guess I'm more curious on the mix with the dividend.

I mean, you were very early to get on this trend of returning a significant amount of cash to shareholders, and it's paid, pardon the pun, but it has paid dividends in both the credibility of the business model as well as the relative performance of the stock.

But why not more dividends over buybacks?

I'm just curious how you think about that?

Do you want to take a crack at it?

Sure.

So look, we have told -- we've explained to the market that we do consider that dividend to be part of the nondiscretionary piece of our capital allocation.

So when we look at that, we look at it in the context of it being effective to the market with our peers and the market in general, but also, more importantly, sustainable through market cycles.

So again, we regularly review that with those objectives in mind.

Doug, what I would -- and Donna is exactly right.

What I would add to what she said, you've got the sustainability aspect in a down market cycle, which is something that we spend a lot of time looking at to be sure that we don't find ourselves cutting the dividend.

And you reinforce that by having a very strong balance sheet.

But if I think about it longer term, okay?

And this is really where my brain goes, it goes to the sustainability of the growth of the dividend going forward.

And we want to continue to be able to grow.

We want to give our owners more every year.

And the way that you go about doing that is tempering it a little bit.

I think we started talking last year about moderating the dividend a little bit more, which I think you saw we did this year.

And the other thing that's really encouraging from my perspective is that we've got these capital projects that are coming on stream.

They are providing significant future earnings potential.

And some of them are longer cash flow cycles, which we haven't done a lot over the last bunch of years, but we got another renewable diesel plant, we've got the coker.

And then if we end up doing the Port Arthur renewable diesel plant in the future.

These are huge EBITDA producing projects, which are going to really reinforce our ability to go ahead and continue to deliver dividend growth going forward.

Now I'm not making you a promise because Lord only knows what might happen, but that would be our objective.

And that's kind of the way we look at investing our capital.

The component part, the percentage of the total payout that's made up of the dividend, that the dividend comprises that's not formulaic.

It's more us looking at all of the factors involved.

And there's a lot of sausage-making that takes place there that we won't get into here.

But I always want to be in a position when we do something like this to let you know that we feel fairly assured that this isn't going to be an issue going forward.

I appreciate the lengthy answer, guys.

My follow-up, Joe, I don't know if you want to throw this to one of the guys and may I also offer my congratulations to the new officers and titles in the team.

But maybe Lane wants to take this.

But there's a lot of chatter about new capacity coming online at backend of this year and maybe for the next couple of years.

Obviously, things are kind of soft, it seems on the demand side, given what's going on with China.

But I'm just wondering how you see the prognosis for the short-term IMO tailwinds transitioning maybe into a more challenging refining environment longer term?

Are you guys thinking about that?

And I'll leave it there.

Thanks Doug.

Yes.

So I think for at least for the next year to 2 years, we see global oil demand growth, kind of keeping pace with the capacity additions, and we don't think we have [imbalances] (corrected by the company after the call) between production and consumption.

But then yes, we start to show 2 to 3 years out, that capacity additions start to outpace global oil demand growth.

And at that time, we would expect to see some rationalization in the industry.

So the next couple of years, you're not concerned about -- I mean, obviously, Aramco has got a bunch of stuff coming online, and then Asia kicks up '21, '22, so you're not concerned about the short term -- kind of medium-term outlook then?

No, we still show that oil demand growth outpaces capacity addition for the short term.

Our next question comes from the line of Paul Sankey from Mizuho.

If I could have a followup on that -- Joe, you ran higher than we expected in every region.

Could you talk about them, and that's obviously versus your guidance.

Could you talk about the pattern of higher volume?

I don't know if there's a volume mass issue there.

But certainly, your capture suggests that's not the right direction to be looking in.

And furthermore, once you've hopefully help us explain how come you're running at the levels that you are right across the system, could you -- and this is a follow-up to the previous question.

Could you talk about any expectations you have for shutdowns in refining, if margins stay extremely weak and potentially get worse with this whole situation in China?

Okay.

So Paul, we'll look -- we're kind of looking at each other, let us give -- take a crack at this and then we'll give you the opportunity, if we're not answering your question to follow-up, okay.

Paul, this is Lane, I'll start.

We've had a long strategy really dating back to 2011 to work in a very organized way on our reliability projects and what we've seen is our refining system has gone from, say, 95% to 96% availability all the way up to sort of over 97% availability, and that's helped us.

We're available and when the market is right and have been able to perform better.

And in addition to that, we do believe that we're the best in the industry in terms of understanding what feedstocks go where in the systems that we're in and we're highly adaptable to that.

So I think that helps us versus some other people in terms of our capture rates, so...

Lane, could you just dig in a little bit on that better than anyone else argument because to an extent, I guess, the computer programs commoditized or not?

If you could just go a bit down that rabbit hole I would be grateful.

It's interesting, you would say they're commoditized because everybody has tools.

Everybody believes that they're all implementing these tools and to some degree or another.

I would say that I believe we are more integrated and more aligned on making sure that our tools characterize the feeds, and we understand our units very well.

It's one thing to have the tool.

Sometimes people have tools, but they don't use the tools.

We have a world-class planning and economics group and they do a fantastic job coordinating with our refineries in terms of having those sub models very well understood.

And therefore, we understand the operating envelopes and how those feedstocks are characterized in our systems.

Yes.

I mean, I guess, further to a previous question, we've seeing big mega-oils, who you would think have a similar structure in terms of their refining footprint to you guys wildly underperforming against what you guys are achieving.

So it's just interesting to try and establish what the competitive advantage is.

Well, we appreciate you saying that, Paul, and then the follow-up question was on capacity.

Yes.

So I think the situation in the Far East is just developing.

And it's really too early for us to be able to judge the magnitude of the impact that's going to have and whether it leads to refineries shutting down or not.

The reality of it is, we've got capacity coming on stream.

We've also got capacity that isn't running well and that in the foreseeable future, probably won't be able to run well.

And so -- and Paul, if you assume at some point, it's a zero-sum game.

There's going to be a lot of capacity that shouldn't run.

Certainly, post IMO world, it's going to have an effect on that.

And so if you got poorly performing assets today, turning them around is a lengthy process.

And then if you've got a marginal asset due to economics, you're going to be the guy that has to bow out at some point in time.

So that's why we look at it, I mean, frankly, our tendency is to focus a whole lot more on our business and what we can do to make it better and more efficient than kind of what's happening more broadly.

Yes.

Got it.

If I could just ask a very specific follow-up.

If we assume that there was extreme weakness in jet fuel demand, what would that mean for you and the global industry?

And I'll leave it there.

Our jet yield is about 8%.

So we make 200,000 to 250,000 barrels a day of jet.

Some of that is contract demand and inland demand, which is going to stay, but a lot of it is in our Gulf Coast refineries, we have the ability to put that into diesel if jet demand got soft, and I suspect that's what would happen.

Our next question comes from the line of Sam Margolin from Wolfe Research.

I know you just said you focus on your own business and not the market, but I have a market question to start.

So...

I didn't say we don't focus on the market.

So a lot of attention is being paid to this collapse in diesel cracks.

Part of the reason that the drop has been so pronounced just because the peak that it started from was so high.

And at the time, when we were at that peak, it seemed obvious why, but in retrospect, IMO is having more of a feedstock effect than a product effect.

So do you have any updated thoughts about that period just 3 months ago when diesel cracks were peaking in retrospect.

What was really driving that?

And maybe that will help inform how we can escape this headwind in the intermediate term?

Yes, Sam.

So I think as we got to the back half of the fourth quarter, obviously, fall turnaround season winded down and we started to see refinery utilization ramp up and with higher refinery utilization, of course, distillate production increased.

And then overall, demand has been weaker than what we anticipated.

So a lot of that's been due to warmer weather.

The warmer weather has somewhat offset a lot of the demand increase, we thought we would get as a result of IMO.

In addition to that, certainly, in the U.S. Gulf Coast, we've had a very heavy fog which has limited our ability to export the diesel to some of the export markets.

In addition to that, we've had very high freight rates, which again, hinder our ability to export.

Of course, South America is a big export market for us.

They've had a lot of rain in South America, which has delayed the harvest.

So again, having a hit to demand.

And then I think the final thing is there was a lot of prestocking of very low sulfur fuel oil that happened in the industry.

And so, so far, it's muted the impact that IMO will have.

We certainly are confident that, that demand will show up, but it may be more of a second quarter type demand increase than what we're seeing so far in the first quarter.

Okay.

And my follow-up is on renewable diesel.

It's been said on this call already, the economics are really strong, it scales very accretively.

On the feedstock side, are there any constraints as you imagine this business getting bigger.

There was another operator in the business who recently pivoted a little bit on the feedstock side and said, tightening was possible in the future.

Do you see any of that?

Or is your -- does the strength of your partnership with Darling kind of help you avoid that friction.

Well, definitely, the strength of our partnership with Darling helps us.

They process 10% of the world's meat byproducts.

So we're in a unique position with the JV we have.

This feedstock is tied to GDP growth per capita and that's growing in the world.

So it's going to tighten up some, but we still feel good about being able to source it, and we don't see that as a constraint with what we've talked about so far.

Our next question comes from the line of Paul Cheng from Scotiabank.

I think that the first one is probably either for Lane or Gary.

You guys historically run the M100, I suppose directly through the crude unit.

Have you tested or whether that you will be -- have the configuration to run, the high sulfur fuel directly through the coker and that if you do that, how big is that capacity you may be able to do here?

And also whether you have export any low sulfur VGO in the fourth quarter?

Paul, this is Lane.

I'll start and Gary can round me.

As you have alluded to, we have a history running M100, but not all M100s are created equal.

There's varying qualities.

We had what we would consider to be a quality window that we've historically ran.

We've widened that.

We do run that.

We run those types of long resids.

They obviously have a little bit of cutter stock, and we typically run them in our crude supply.

And so as we raise the percentages of them, you think about, well, what we're doing as we're running those to fill, to destroy the resid and obviously it makes -- fills out the bottom of the refinery.

And then we're running light sweet crude as a supplement to that because that's been an advantaged crude really for the past year.

So it's really, over time, we were optimizing by looking at all the domestic light sweet with these resids opening the call -- the operating envelope for all the resids that we can find in the world.

And then we are constantly optimizing that versus the heavy sour crude availability.

And that's kind of how we always run.

We've just -- we've worked really hard to characterize some of these that are new to the market and are trying to run more of them.

So what was your second question.

No.

I mean, the first one, have you exported any low sulfur VGO.

Yes.

So our economic signals have been to pull low sulfur VGO out of the cat crackers, and we did sell quite a bit of it in the fourth quarter.

And so far in the first quarter, we're seeing the same economic signals.

In addition to that, we're -- so Paul, in addition to that, we're also exporting a lot of low sulfur ATBs that we normally run in our FCCs as well.

What kind of economic and how much you have export?

I mean, is that part of the reason why your margin has been perhaps the better than people thought?

Yes.

I mean, we -- we were selling those, particularly low sulfur ATBs and some of the other hydro process resids, quite a bit above -- quite a bit above what they historically been worth.

Yes.

And is there a volume that you can share?

Is it, say, 50,000 barrel per day or 100,000 barrel per day.

Any kind of rough number?

No, we probably don't really want to share that.

Okay.

Final one, you run 180,000 barrel per day of the WCS.

Is there any more room that you would be able to expand that?

Yes, there is.

So we have -- we primarily run the Canadian at Port Arthur in Texas City.

We can also take it to St.

Charles, and we have plenty of capacity to run more Canadian.

How about supply?

Can you get it there?

Yes, we can.

So today, a lot of the problem is certainly pipelines coming out of Western Canada are full, but we buy off the pipeline, and we also continue to take volume by rail.

So I think in the fourth quarter, we did a little below 38,000 barrels a day of heavy Canadian by rail.

We're seeing those volumes ramp up in the first quarter and expect them to ramp up even more in the second quarter.

Our next question comes from the line of Neil Mehta from Goldman Sachs.

Let me add my congratulations to Lane and Gary here on the promotions.

I guess, my first question is, we spend a lot more time than we ever have with investors on the issue of sustainability and carbon intensity.

And it's really the "E" side of the ESG.

And Joe, maybe you could just talk high level how you think about Valero's framework for talking to investors about ESG and carbon intensity.

Do you feel like you're there where you want to be on carbon targets and disclosure and then I would think the renewable diesel business becomes a big part of the narrative of how you respond to any difference that might emerge around.

Yes.

Neil, that's a really good question.

And you are right, we do spend a lot of time on this.

And frankly, I think Valero's got a great story.

Jason is responsible.

He and John are jointly responsible for our efforts around this.

And we made a lot of progress.

And I'll let those 2 guys speak to this in some detail.

Yes, this is Jason.

Neil, I'll be glad to talk to you a little bit about it.

And as you -- the point you made about strategy is of course correct.

2 of our 3 segments are now renewable.

We're the largest renewable diesel producer in the U.S. through DGD, second largest producer of ethanol and we continue to look at that area and expand it as we've discussed.

And we're also looking at other low carbon fuels and ways to lower our carbon intensity in our existing business.

So just as a business footprint, I think, we've been evolving to as the market expectations have changed.

I think we've done a good job on that side.

And on the environment side, we're very mindful about environmental impact.

We've always been proud of our record.

In 2019, we had our best ever performance on our environmental scorecard events.

It is the lowest number we've ever had and safety has always been a big focus of ours.

In 2019, our refining employee injury rate was our best ever, and the combined employee contractor rate was of second lowest in company history.

We think we have a good governance structure.

10 of our 11 directors are independent.

We have substantial diversity is something we're always working on.

We have really good risk oversight and risk management within our governance structure.

And then on the disclosure area, which is one of the things you asked about, we've definitely beefed it up here in the last couple of years as we put more focus on the ES&G area.

In September 2018, we published our report on climate-related risks and opportunities.

And we prepared that in alignment with the TCFD recommendations, which seems to be more and more -- our investors seem to be coalesced around that as being the standard they want.

There are a lot of competing regimes out there.

Just good to see some standardization kind of come into play.

And then we also put out a stewardship and responsibility report annually, where we talk about -- some about the carbon stuff, but also about other sustainability oriented areas, and we're continuing to work on that every year to try to make it better.

And I know there's been some large investors, focusing on SASB as being maybe the standard.

And once again, outside of carbon, there's been a lot of variability in different disclosure structures and what people may want.

So we're taking a hard look at SASB this year and comparing to what we're doing to see if we need to tweak some things there.

We are always looking to improve.

Right.

Appreciate it.

And then the follow-up question actually relates to RINs, which I know is collectively our least favored topic.

But there were some headlines recently around the court cases around RINs exemption and a small waiver.

The waivers for some of the smaller refiners from a couple of years ago.

Do you see any risk that this becomes an issue that could put upward price pressure on RINs again?

Go ahead.

Okay.

Yes, this is Jason, again.

We did see that Tenth Circuit case out of Denver last week.

And what it did was vacated SREs for 3 refineries, 2 of HollyFrontier's and 1 of CVR's.

And the EPA has several options, including appeal, expect they will probably will appeal, like neither appeal and have the Tenth Circuit that -- hear the case as a whole or go straight to the Supreme Court, and we know they're evaluating their options to see.

So court took a reading of the statute in a fairly constrained view that as far as I know, has been done by court in the past and it's definitely not in keeping with the view the EPA has had.

The way they've interpreted the statutes in the past.

So we really have to see what the EPA does with it to get an idea of how impactful this is.

One important point is because it was at the Tenth Circuit, because the DC Circuit, which is a decision that plaintiffs made and when they filed it, it's only has legal effect within the Tenth Circuit.

So it only binds the EPA within those 6 states that are covered by the Tenth Circuit.

So let's see how it evolves.

Yes, we'll see how it plays out.

I think, it's probably too early to give a market signal on RINs prices as a result of this case really.

Our next question comes from the line of Theresa Chen from Barclays.

Joe, I'd like to touch on your comments earlier about Permian pipes to Gulf Coast and narrowing of inland diffs.

And as far as developments at Corpus Christi goes, there's been continued discussion on potential dock constraints in the area.

And based on one of your competitors' releases yesterday, it seems that one of the bigger dock projects that may be delayed a bit.

What is your current outlook on the possibility that we might have a glut of crude at Corpus, which I'm sure would benefit your facilities there.

And if there are indeed dock constraints, would this affect MEH first since there's no public price and then affect Midland if things really get backed up?

Or how should we think about that?

Yes, Theresa, it's a good question.

Gary is close to this.

Let him talk about it for a minute.

Yes.

So we're -- when we look at this, it looks like there will be plenty of dock capacity available, but there are some periods of time where it could get very tight.

And so our focus really has been to make sure that we're connected to all of these lines coming out of the Permian, and we can take barrels to Corpus or Three Rivers.

And then we've also put efforts into expanding our dock capacity from our Corpus Christi refinery.

So part of that project is completed.

By early second quarter, we'll have that project 100% completed and essentially double our export capacity that we'll be able to put through our system.

The second part of your question, yes, I would expect it to really affect the MEH posting first.

And then yes, it will probably work its way back into the Permian as time goes on.

Got it.

And switching gears a bit.

So the natural gas pricing outlook seems pretty depressed.

Can you talk about how much of a tailwind this could be for your business this year?

Well, this is Lane.

So net, obviously, energy is a big part of the cost structure in our business.

And it's been depressed for a while.

So it's -- obviously, it works not only to our advantage, but really the industry's advantage to compete in the world.

I mean, natural gas is how we run these refineries largely.

And it's a big advantage for U.S. refining in general.

Yes, really all industrial activity.

Yes, really industrial activity.

Our next question comes from the line of Benny Wong from Morgan Stanley.

I just kind of want to follow-up on Paul's question around the Canadian barrels.

There's more talk up north about building diluent recovery units.

Just wanted to get your perspective on that, if that's kind of a viable path for more Canadian barrels to reach the U.S. Gulf Coast.

And just curious, have you kind of tested any of these unblended bitumen in your facilities?

And if they're really the more desirable type of feedstock, that's what's been touted as.

So this is Gary.

And yes, we took bitumen directly from Western Canada and ran it at our refinery at St.

Charles and have ongoing discussions with several producers.

You can just move a lot more by rail if you take the undiluted barrel and it would fit well into our system, and we have plenty of capacity to be able to run it.

I appreciate that.

And my follow-up is more on the RFS program and maybe Jason can chime in on this.

There seems to be more focus in D.C. about what that program will look like after it sunsets in 2020?

And it seems like the thought of setting a higher octane gasoline standard is alive again.

Just wanted to get your thoughts on that?

And if there is really a path for at this time?

Or -- and I guess, how you think about that program beyond 2020, too.

Sure.

Yes.

And this is Jason.

And you're right, the tables that set the volumes expire in 2020.

The program falls back into the hands of the EPA to set the volumes using certain standards as a guide and it's still open.

They hadn't signaled a lot about what they're going to do, but we would like the higher octane fuels to be part of the solution.

We think that's a great answer.

It's great for the autos, it enables them to meet their CAFE, it's great for us.

It keeps internal combustion engine more viable in this lower carbon world and more of a vibrant competitor.

And it is great for the ethanol guys because they're a good choice of low-cost octane.

So really, it's a win, win, win solution and we would like to see get traction.

And we definitely are talking it up.

We think it's a great solution for the country.

Our next question comes from the line of Roger Read from Wells Fargo.

Lot of the good stuff has already been hit here, but maybe just to dig in a little bit more on sort of the, let's call it, the North American performance versus the global performance.

And you've mentioned some benefits from naphtha, some benefits from natural gas and from butane.

There were also in the last couple of months, issues with tanker rates and things like that.

So as those events, let's call it, normalized or in this business where everybody takes advantage of them pretty quickly, we arb away those advantages.

What looks more sustainable for you here in the next few months versus what looks transitory, not just worried so much or thinking, hey, we're going to go to summer-grade gasoline, which has its own benefits, just curious there what you're seeing?

Yes, I think overall, as long as the U.S. production is having to clear to the export markets despite where freight rates go, we'll see good advantage running domestic light sweet crude in many of our assets.

We also see that running the heavy sour and the high sulfur fuel oil blend stocks into our high complexity assets looks to be very favorable for the foreseeable future as well as a result of the IMO bunker spec change.

Outside of that, I don't know what else I would add.

Roger, It is Lane.

I just wanted to add one thing.

I think what you're really seeing is, as we alluded to, we're marketing low sulfur VGO and low sulfur ATB into the low sulfur fuel oil market.

And then what that does is that really is constructive for FCC -- for gasoline because FCCs are going to be cut.

I mean, we've sort of talked about it over the past -- really for the last 2 years, when we were talking about IMO, and that part of it is certainly playing out.

I mean, you'll see as the gasoline season rolls in, you'll get a -- essentially, that market is going to have to compete for feed into the gasoline market.

So it should be supportive of both really sort of both gasoline and diesel.

Okay.

Yes, that's helpful.

And then maybe back to Theresa's question about natural gas.

Obviously, cash OpEx guidance of over 4 is kind of higher than what we've seen over the last few years.

And I know there's been some changes in the consolidation of VLP and all that.

But I was just curious, is that something that can be a help on the OpEx side that we should see?

Or are there other things moving around here they're going to keep OpEx on the upper end?

Roger, if you look at -- Lane again, if you compare our guidance to last -- basically first quarter '20 to first quarter '19, it's pretty much flat.

That's sort of our large turnaround time frame.

And so I would just sort of say that's flat year-over-year.

But when you look at the longer term, certainly we've had realignment reporting structures.

We moved the renewable in the Diamond Green Diesel out, and we've taken all the MLP stuff, which would have been in our sort of cost of goods, and it came into our Opex.

And so as we realigned all that stuff, it sort of resulted in a little bit -- in terms of our OpEx a little bit higher.

And then overall, there are -- obviously, there's some inflationary pressures in the world.

When you -- again, when you compare our overall cash OpEx performance on sort of what we would call a Solomon basis, we are by far in the first quartile, so which means we are the pacesetters in the industry when it comes to cost.

Our next question comes from the line of Brad Heffern from RBC.

A question maybe for Lane on throughput.

So this quarter, there was almost 1.7 million barrels a day in sweet.

I think you guys have quoted that capacity historically is more like 1.6.

So is there something that's changed?

Is that something that running the resid is allowing you to do?

And then how should we think about that going forward with some of the diffs like Maya widening out?

So what you're, I kind of touched on it a little bit earlier, as we're running more and more resid, the resid doesn't really have that much light-end components.

So as it substitutes and sort of moves out either heavy or really -- the real thing that we're backing out, if you look at year-over-year is medium sour.

So what's happening is we're running more and more light sweet, which -- and what that's doing is sort of it's substituting for medium sour which does have some light ends to it.

So that's a journey we're on.

We've been signaling max light sweet crude and max heavy, and we optimize between heavy sour crudes and resid.

And so we'll -- and I don't know that we can go a whole lot higher, but we'll just see quarter-to-quarter and see how much higher we can go.

Okay.

And then, Joe, in your prepared comments, you were talking about sort of the different things competing for capital, and you mentioned M&A as you have in the past.

I know you haven't done a whole bunch recently.

You've done some ethanol deals and the terminals acquisition.

I guess, can you just put any meat on that in terms of what you would potentially be interested in on the M&A front?

Yes, why don't we let Rich talk about that?

Sure.

This is Rich.

So yes, we continue to look at the opportunities as they arrive, as they arise.

A lot of this stuff tends to be in niche markets.

And we're focused on the Gulf Coast and just haven't seen a lot of things arise there.

That's where we would capture the synergies and where we would have the advantage.

So I mean, we look at everything as it comes up, but we don't see any opportunities that compete against the pipeline of organic projects that we have.

So nothing major on the horizon.

Yes, that's right.

Our next question comes from the line of Jason Gabelman from Cowen.

I'd like to ask a question about the ethanol and renewable diesel segments.

It looks like the indicators have fallen quite a bit from 4Q to year-to-date.

And I'm just wondering what's going on in those 2 markets?

And how you see that evolving throughout the course of the year?

And I have a follow-up.

Okay.

This is Martin.

On the renewable diesel, the indicator drops because the -- you have the blenders tax credit in place now.

So we gave up a little bit on the RIN, feedstock costs got a little higher, but you need to add $1 a gallon to that indicator to get really where market is.

So again, we're $1.26 pro forma, but that's really a $2.26 EBITDA per gallon.

So that one is not concerning at all.

Fourth quarter ethanol was, what, $0.14 a gallon EBITDA was our performance, that's come in, and you're correct there.

January is always tough in the business.

I mean, domestic gasoline demand is low, ethanol inventories always build in January.

Really what's happened in the ethanol space, we've been oversupplied in the U.S. for several years.

Exports were growing at 30% CAGR, up through '18, '19.

They took a breather, and that was really due to low sugar prices in the world.

So Brazil made more ethanol.

Right now though sugar prices are up 20% versus where they averaged 2019 and export demand is strong.

We're seeing really good numbers in December, January, February and March.

So we still -- ethanol is in the fuel mix to stay in the U.S. Little bit of incremental E15 and then hopefully, this higher octane standard would really help the industry, obviously.

So we're still optimistic about the future.

I appreciate those thoughts.

And then if I could just go back to running resid, high sulfur fuel oil.

Can you just put some numbers around or discuss how much of that -- those intermediates you're running and backing out crude as a result?

And how much of that is incremental feedstocks?

And in addition to that, are there any type of indicative economics that you could give on running those barrels.

I understand there's a lot of moving parts, but are we talking low single-digit dollar per barrel, high single-digit dollar per barrel in the double digit range?

Just to give us a sense of what the uptake is.

So this is Lane.

We're not going to share our detailed volumes in terms of how we do all that.

And obviously, the relative margins are all a function of what the market is.

They're not fixed off one another.

There is a dynamic market out there.

There's a function of the crude market, the high sulfur fuel oil market, the low sulfur fuel oil market, the latter 2 of which are still trying to sort themselves out with respect to IMO 2020.

So these things vary just like any other feedstock that we run.

There's not a guaranteed margin relative to one another.

And the -- as all the refining capacity looks at all this and optimizes, then if they -- the margins are going to be different over time.

So there's nothing that -- there's not anything we can communicate that you can hang your hat on, per se.

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

I wanted to check in on asphalt and pet coke.

I know it's only about 3% of your product slate, but how has pricing and realizations fared on these areas, just given all the volatility on high sulfur fuel oil and the recent weakness?

Yes.

So this is Gary.

I think, overall, we've been surprised that asphalt margins have stayed relatively strong.

We thought that there may be an attempt to push a lot of these high sulfur resids into the asphalt market, and you would see weakness.

But thus far, asphalt margins in our system have remained strong.

And I wouldn't say we've seen much of an impact at all on pet coke.

Sounds good.

And then the sales volumes in renewable diesel were quite strong in the fourth quarter.

Just wanted to confirm, was that a result of selling down some inventory?

Or did the plant actually run at those levels?

We ran at those levels.

Our next question comes from the line of Chris Sighinolfi from Jefferies.

I wanted to follow-up on Neil's earlier sustainability question, if I could.

And I just have 2 quick questions.

I guess, first, Joe, have you looked at CCUS investment to capture incremental carbon off this facilities?

I know some of your integrated peers are working on that specifically on ethanol facilities to using some of their EOR operations.

So I'm just wondering if it's something you looked at and what the opportunity set might be?

We are looking at it.

Yes.

And Martin and Rich are -- they got a team put together, and we're kind of down the road on this.

I think -- I guess, the real question that we're trying to -- we always are wondering about what's the cost of carbon is going to be, what are the economics going to look like on an investment in a project like this.

So we are looking at it, though.

Okay.

And then I guess, second, in light of the BTC extension DGD JV has clearly become more valuable as noted, it's a key pillar in your environmental sustainability story, which is clearly set apart from your refining peers.

But, Joe, I'm just curious, do you think you get appropriate credit for that and the ethanol franchise within Valero?

And I guess, what are any thoughts or internal evaluation about if or when those businesses might make more sense being independent?

Yes.

Well, those are 2 very different questions.

One is, do we think it matters from an ES&G perspective, and I think it definitely does.

We have a very clear view of what -- where things are going and what the world is demanding now.

And we really believe renewable fuel is a key component of that.

And the good news is that they both happen to be great businesses, and we've got great assets and good teams running them.

So I think as time goes on, people will see that Valero is somewhat differentiated perhaps from others out there because of these investments.

As far as separating them off, my view is they are producers of motor fuels and different types of motor fuels, very low carbon intensity motor fuels, but they're motor fuels, and Valero produces motor fuels.

That's what our business is, and we do it really well.

And these are largely process operations and they integrate well.

Processes that we've implemented on the refining side are scalable to our ethanol plants and to the renewable diesel operations.

And so I think, frankly, being embedded in the company, it brings more value to Valero than it would to split it out.

At this time, I'm showing no further questions.

I would like to turn the call back over to Homer Bhullar for closing remarks.

Great.

Thank you.

We appreciate everyone joining us today.

And if you have any follow-up questions, please feel free to reach out to the IR team.

Thank you.

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

Thank you for participating.

You may now disconnect.