Greetings, and welcome to Valero Second Quarter Earnings Conference Call. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Homer Bhullar, Vice President, Investor Relations.

Good morning, everyone, and welcome to Valero Energy Corporation's Second Quarter 2020 Earnings Conference Call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; 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. This year has been challenging in many aspects. The COVID-19 pandemic and the ensuing global economic downturn has affected the health and livelihoods of so many people and has had a severe impact on all businesses, including ours. As troubling as our circumstances may be from time to time, it's gratifying to see individuals stepping up, selflessly helping those in need whether it be by providing health care to those that are sick or food to those that are hungry. In this regard, our team is doing its part. As you probably know, Valero's part of the country's critical infrastructure. As such, our team continues to operate our plants, providing the fuel that our country needs to keep critical supplies and first responders moving. I'm proud that we have not laid off, furloughed or reduced the compensation of any of our 10,000 dedicated employees who continue to give generously, volunteering their time and working courageously and tirelessly through this difficult period. Our employees are our greatest asset and the heart of our company. Their health, safety and well-being remain among our top priorities. And we'll continue to take the steps necessary to keep them safe whether they work in the field or at our headquarters. In response to the COVID-19 pandemic-imposed shutdown, we had to make important operational and financial decisions. When the stay-at-home orders were first issued, we reduced our refinery and ethanol plant throughput rates to match product supply with demand. We saw demand in April bottom out at 50% of normal demand for gasoline, 70% for diesel and 30% for jet fuel relative to the same period last year. As the stay-at-home orders and travel restrictions eased through most regions of the U.S. during the second quarter, we saw gasoline and diesel demand recover to 85% to 90% of normal, and jet fuel recovered to 50% of normal. We also saw a recovery in product exports to Latin America and Europe in June. As a result, we prudently increased refining and ethanol throughput rates in step with the increase in product demand. We also took prudent actions to maintain our financial strength. We lowered our 2020 capital budget by $400 million; raised $1.5 billion of debt at attractive rates; secured an additional credit facility, which remains undrawn; and temporarily suspended the stock buyback program beginning in mid-March this year. And through all of this, we've honored our commitment to capital discipline and maintained our dividend as demonstrated by our Board of Directors approving a quarterly dividend of $0.98 per share earlier this month. Notwithstanding project deferrals this year, we continue to invest for earnings growth and are making progress on strategic projects under development. The St. Charles Alkylation Unit, which is designed to convert low-value feedstocks into a premium alkylate product, is on track to be completed in the fourth quarter of this year. The Diamond Pipeline expansion and the Pembroke Cogen project are expected to be completed in 2021, and the Port Arthur Coker project is expected to be completed in 2023. And we remain committed to the expansion of our low-carbon renewable diesel business. The Diamond Green Diesel expansion project is expected to be completed in 2021. This project is expected to increase annual renewable diesel production capacity by 400 million gallons per year, bringing the total capacity to 675 million gallons per year. In addition, the Diamond Green Diesel continues to make progress on the advanced engineering review for a potential new 400 million gallons per year renewable diesel plant at our Port Arthur, Texas facility. As we focus on the path to recovery with improving product demand, we remain steadfast in the execution of our strategy, pursuing excellence in our operations, investing for earnings growth with lower volatility and honoring our commitment to stockholder returns. We continue to prioritize our investment-grade credit rating and nondiscretionary uses of capital, including sustaining capital expenditures and our dividend. This uncompromising focus on capital discipline and execution has served us well in the current pandemic-imposed downturn, and it should continue to position Valero well through the recovery and beyond. So with that, Homer, I'll hand the call back to you.

Thanks, Joe. For the second quarter of 2020, net income attributable to Valero stockholders was $1.3 billion or $3.07 per share compared to net income of $612 million or $1.47 per share for the second quarter of 2019. Second quarter 2020 adjusted net loss attributable to Valero stockholders was $504 million or $1.25 per share compared to adjusted net income of $665 million or $1.60 per share for the second quarter of 2019. Second quarter 2020 adjusted results exclude the benefit from an after-tax lower of cost or market or LCM inventory valuation adjustment of approximately $1.8 billion. For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany the release. Operating income for the refining segment was $1.8 billion in the second quarter of 2020 compared to $1 billion in the second quarter of 2019. Excluding the LCM inventory valuation adjustment, the second quarter 2020 adjusted operating loss for the refining segment was $383 million. Second quarter 2020 results were impacted by lower product demand and lower prices as a result of the COVID-19 pandemic. Refining throughput volumes averaged 2.3 million barrels per day, which was lower than the second quarter of 2019 due to lower product demand. Throughput capacity utilization was 74% in second quarter of 2020. Refining cash operating expenses of $4.39 per barrel were $0.59 per barrel higher than the second quarter of 2019 primarily due to the effect of lower throughput rates. Operating income for the renewable diesel segment was $129 million in the second quarter of 2020 compared to $77 million in the second quarter of 2019. After adjusting for the retroactive Blender's Tax Credit, adjusted renewable diesel operating income was $145 million for the second quarter of 2019. Renewable diesel sales volumes averaged 795,000 gallons per day in the second quarter of 2020, an increase of 26,000 gallons per day versus the second quarter of 2019. Operating income for the ethanol segment was $91 million in the second quarter of 2020 compared to $7 million in the second quarter of 2019. Excluding the benefit from the LCM inventory valuation adjustment, the second quarter 2020 adjusted operating loss for the ethanol segment was $20 million. Ethanol production volumes averaged 2.3 million gallons per day in the second quarter of 2020, which is 2.2 million gallons per day lower than the second quarter of 2019. The decrease in adjusted operating income from the second quarter of 2019 was primarily due to lower margins resulting from lower ethanol prices and lower throughput. For the second quarter of 2020, general and administrative expenses were $169 million, and net interest expense was $142 million. Depreciation and amortization expense was $578 million, and the income tax expense was $339 million in the second quarter of 2020. The effective tax rate was 20%, which was affected by the results of certain of our international operations that are taxed at rates that are lower than the U.S. statutory rate. Net cash provided by operating activities was $736 million in the second quarter of 2020. Excluding the favorable impact from the change in working capital of $629 million as well as our joint venture partner's 50% share of Diamond Green Diesel's net cash provided by operating activities excluding changes in its working capital, adjusted net cash provided by operating activities was $38 million. With regard to investing activities, we made $503 million of capital investments in the second quarter of 2020, of which approximately $240 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance. Approximately $263 million of the total was for growing the business. Excluding our partner's 50% share of Diamond Green Diesel's capital investments, Valero's capital investments were approximately $448 million. Moving to financing activities. We returned $400 million to our stockholders in the second quarter of 2020 through our dividend, resulting in a year-to-date total payout ratio of 96% of adjusted net cash provided by operating activities. As of June 30, we had approximately $1.4 billion of share repurchase authorization remaining. And on July 16, our Board of Directors approved a quarterly dividend of $0.98 per share, further demonstrating our sound financial position and commitment to return cash to our investors. With respect to balance sheet at quarter end, total debt and finance lease obligations were $12.7 billion, and cash and cash equivalents were $2.3 billion. The debt capitalization ratio, net of cash and cash equivalents, was 33%. At the end of June, we had $5.7 billion of available liquidity, excluding cash. Turning to guidance. We still expect annual capital investments for 2020 to be approximately $2.1 billion, which includes expenditures for turnarounds, catalysts and joint venture investments, with about 60% allocated to sustaining the business and 40% to growth. Approximately 30% of our overall growth CapEx for 2020 is allocated to expanding our renewables business. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.4 million to 1.45 million barrels per day, U.S. Mid-Continent at 380,000 to 400,000 barrels per day, U.S. West Coast at 215,000 to 235,000 barrels per day and North Atlantic at 375,000 to 395,000 barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $4.40 per barrel. With respect to the 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. Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the third quarter. Operating expenses should average $0.38 per gallon, which includes $0.06 per gallon for noncash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $145 million. And total depreciation and amortization expense should be approximately $580 million. For 2020, we expect G&A expenses, excluding corporate depreciation, to be approximately $825 million. And we expect the RINs expense for the year to be between $400 million and $500 million. Lastly, as discussed on our last earnings call due to the impact of the beneficial tax provisions in the CARES Act as well as the COVID-19 pandemic and its impact on our business, we are not providing any guidance on our effective tax rate for 2020. That concludes our opening remarks.

Our first question today comes from Prashant Rao of Citigroup.

So I wanted to start on the demand recovery. Joe, you mentioned the rapid recovery in product demand through 2Q. Can we get a sense of the strength of product demand as we entered the current quarter and how it's been trending since? And if you could, any color on how to think about that in terms of buckets of gasoline versus jet versus diesel and everything else?

Yes. Sure. Gary, you want to?

Yes, sure. I'll walk you through it. So I'll start with gasoline. As Joe mentioned, we saw demand fall off to about 50% of what we would normally have. Our export volumes fell to about one-third of where they would typically be in the second quarter. But as you mentioned, demand has certainly recovered faster than most people have expected. By May, we were at 77% normal gasoline demand in our system. In June, 88% of normal, and we've continued to see recovery as we transition into July. On the export side, as I mentioned, we bottomed out about one-third of the volume we typically export in the quarter. By June, we were back to 70% of our normal export volume. July, with the estimates we have today, we'd be about 76% of normal on our export volume. So gasoline demand has recovered much faster than certainly most would have expected and appears to be pretty strong. On the distillate side, the magnitude of the demand destruction wasn't nearly as great. As we mentioned, we fell off to about 70% of typical demand. But diesel demand recovered pretty quickly back to about 80% of normal. In our system, we've remained about 80% to 85% of normal demand. However, that's below what the DOE was reporting. The DOE is closer to 94% diesel demand. I think the difference there is certainly in our Three Rivers and the key system, we had a lot of diesel going into the upstream sector. And with lower drilling activity, we're seeing a little less diesel demand than maybe we're seeing nationwide. Also just like gasoline in the export market, we fell off to about one-third of our typical export volume in May. Just like gasoline has recovered at a pretty good pace, actually stronger. In June, we were back to about 45% of our normal export demand. And things have really picked up for diesel export demand in July. Our current estimate for July, we show July export volume's 107% of where they were in July of 2019. I think the other thing that's really interesting when you look at the export numbers is looking at those export numbers in light of the U.S. Gulf Coast diesel production. So if you look at our export volumes last year in July, we exported about one-third of what our refineries produced, the diesel they produced. July of this year with our estimate on exports to be 47%. So almost half of what our refineries are making are going to the export markets. On the jet side, we're also seeing recovery in demand. This week's DOE stats would show jet demand about 60% of normal. I think the DOE data really highlights the importance of the recovery in jet demand because as jet demand has recovered, you've seen diesel yields from refinery fall off significantly. So where we've peaked at about 39% diesel yield, that's come down to about 32% diesel yield. As you continue to see jet demand recovery, you'll see diesel yield fall off from the refineries, which will really help the diesel supply demand balances. I think on the jet side, that would be the only sign that we're seeing that's a little bit troubling. Certainly with some of the renewed efforts to slow the spread of the pandemic and many of the states shutting down, we don't have a lot of good line of sight into jet demand, but some of our nominations for August demand are down a little bit from what we saw in July.

Excellent. That's a great answer. My follow-up is just on the balance sheet. Net debt-to-cap held in pretty well sequentially. And free cash flow, including the working cap tailwind, was positive in the quarter. Given what we're seeing in the demand recovery and the commentary around where we are in 3Q, if we can hold at these levels, if not improve slowly from here, does it feel like you're already starting to turn the corner a bit on the balance sheet? That is to say the defensive measures that you've taken so far this year feel sufficient to ride out this downturn, absent another pullback in demand?

Hey, this is Jason. Yes. I think you're right. With the liquidity we have now, the $2.3 billion in cash and $5.7 billion of other liquidity available, we do think that's adequate for what we see this — how we see it playing out right now.

Okay. Fantastic. And Jason, congrats on the promotion and stepping into the new role. I look forward to talking to you more on that front in the future.

Thanks. I appreciate it.

Thanks, Prashant.

The next question is from Theresa Chen of Barclays.

Just a quick follow-up on Prashant's question related to the demand side and your commentary about LatAm. The current estimates of, I think it was 107% versus normalized levels that you're seeing, how much of that you think is pent-up demand? Or is it sustainable? And related, do you think that any of the refineries that were previously maybe not optimal or operating at optimized capacity would perhaps permanently shut down or be permanently impaired economically in that region such that perhaps you can take some market share going forward?

Yes. So I think what we've seen, at least for the export markets we go to in Latin America, their demand recovery has been very close to the same type demand recovery we're seeing in the United States. I do think you may have some prefilling of inventories getting ready for winter, which could cause exports to spike a little bit. But in our system, we see a pretty steady flow of diesel volume to Latin America, and the volumes are fairly constant. Where we really get a spike in our export volumes is when the arb to Europe is open. And that arb is currently open as it has been much of July, and that's where a lot of that incremental volume is going.

Got it. And then switching to the differential front. So we seem to have several pipeline or projects in regulatory purgatory. And just given your expansive commercial presence, I'd be interested to hear your views on how differentials could react specifically to DAPL. So if the pipe is shut down, how do you think that will impact not only Bakken differentials, but also WTI? And do you think that could create perhaps like a pull on Cushing? What are your thoughts here?

Yes. So definitely, if DAPL isn't allowed to operate, it certainly will pressure the Bakken differentials. We could see that moving weaker. Enbridge came out yesterday. They have some efforts to improve their capacity to help clear the Bakken. Of course, through that Enbridge system, we are connected. We are on Line 9 to Québec. So we'd have an opportunity to bring that Bakken volume to Québec, which would be a benefit for us. In terms of the WTI differentials, I think with where we are on the forecast for production and where pipeline capacity is, I don't see it really having a significant impact on the WTI differentials. I think we're kind of in a mode where Brent-WTI probably is in that $2 to $3 range based on the incremental cost to get it to the Gulf and clear.

Understood. Congratulations to Jason as well.

Thank you.

The next question is from Manav Gupta of Crédit Suisse.

First is a more of a policy question at this point.

Hey, Manav, we can barely hear you, man.

So is it better now?

Sorry.

Yes. So on the policy side, at this point, President Joe Biden's clean energy agenda does not have renewable diesel in it, but there is a school of thought that you can't post the big trucks and buses to go on electric, but you can encourage them to go on renewable diesel. Do you see a chance that the clean energy agenda of the Democratic nominee expands and includes renewable diesel at some point of time?

Manav, everybody fainted when you made your first proclamation. We'll let Rich Halls take a shot at the answer, okay?

So we have some familiarity with Biden and some of his priorities. And one of the things that I would point out is that nobody's going to want to take the union jobs away that are associated with the manufacturing that we have out there. There's a huge amount of infrastructure in the country that's based on that. Same thing with the renewable fuels. I don't think that any administration that comes in is going to want to pull the rug out from under the farmlands. And so we see renewable diesel having a big role to play, a significant role to play. And I know there's a lot of aspirational statements and positions out there about electrification, but there's a big marketplace for renewable diesel, and we think it fits strongly in the energy mix.

Martin, anything you want to add to that?

No, I'd just echo that. When you look at — when you get to the true numbers, if you look at the carbon intensity, renewable diesel competes very well with so-called zero-emission vehicles. You're already up to 16%, 18% renewable diesel in California. You've got mandates out to 2030 in California and Europe, the clean fuel standard coming in Canada, New York proceeding. So we just — as Rich said, we just feel really good about the future and the growth and just see this worldwide globally as in the fuel mix for a long time to come.

That was helpful. One quick follow-up. So the Monday indicators which you put out, which are very helpful, are basically indicating that when you look at all the regions versus May, every region is showing some improvement. But Gulf Coast, where your most of your capacity is actually showing a $3 per barrel improvement, so I'm just trying to understand, on the margin front, why is the rate of change on the Gulf Coast showing a better positive variance versus some of the other regions?

Probably the biggest variance is due to the crude differentials. So crude differentials have been very tight, but we've seen medium sours move $0.60 in the last few days, and we've seen the Canadian heavy move $1. And so on our Gulf Coast, we run a lot more of the medium and heavy sours, and so that would have the positive impact on the margin indicator versus the other regions, which are primarily sweet.

The next question is from Paul Sankey of Hubbard.

Yes, it's Analyst Hub, actually, not Hubbard. But anyway, Joe, it's been a long 6 months, 4 months since we last spoke. And I was wondering the extent to which you feel world has changed on a secular basis. Obviously, you've referred to the demand side, and we can debate how air travel and what suburbanization is more gasoline intense, but clearly, you've accessed capital. You've seen very clearly to be restating the dividend commitment that you've had since you became CEO. I guess one question would be where you think we're going in terms of how U.S. crude markets change? It does seem that we're in for a very different outlook now in terms of how much available crude there is in the U.S. and how the balance will shift. Equally, we've heard a reference already, and thanks for the about how the election may change things, but any further comments you have on that would be very interesting.

Yes, you bet. Paul, I mean, just looking back over the last 6 months, it's been a bit of a roller coaster, right? When we started off the year in pretty decent shape, and then we had the incredible trough. Most of us in this room have been in this business for a very long time. And you got to look back a lot of quarters before you see a quarter like the second quarter of this year. It was just brutal. I mean, the margins were just horrible. And so anyway, the one thing that we're focused on really is that we're going to run the business for the long term. And we need to have a steady hand right now and just continue to focus on doing what we do and doing it well. We're dealing with news that's barraging us every day with negative commentary, and people are fearful. And we've got an election coming on. And you and I probably could have a lively conversation about the impacts of that. But frankly, we're coming out of this. And I think if you look at our country and the way that people want to live, it is not the way that they lived over the last quarter. So anyway, I'll stop there. Gary, talk a little bit about crude situation?

Yes. So I think most forecasts we see confirm what you're talking about. As total oil demand picks up, I think a greater percentage of that gets filled with more sour production. Our view is that the U.S. will still be a net exporter of crude oil. And as long as the U.S. is exporting crude oil, we'll continue to have advantage on the light sweet barrels we're bringing into our system. And then of course, with the flexibility that we have, especially with our complex Gulf Coast refining assets, getting some more medium and heavy sour barrels on the market will help us as well from that aspect.

And then as far as your — no, Paul, and you mentioned the election. And we don't have a crystal ball on what's going to happen. But we do know that if you just look fundamentally at where we are, the products that we produce are necessary for life as we know it. And so you can have a lot of conversation around what we're going to do and what needs to — but in reality, fossil fuels are going to be with us for a very long time. And demand forecasts continue to be for increased crude oil consumption going forward as countries continue to develop and so on. So we just need to not get hung up in the — think we're going to be in this dungeon that we're in now forever.

Yes. I mean, obviously, a vaccine would change that. I think I've read from your comments very clearly that the strength of demand is really impressive. If you think we've just printed minus 30% GDP, and we've got yesterday, gasoline demand down 8%, it's actually quite incredible.

You bet. Take care.

The next question is from Doug Terreson of Evercore ISI.

So my question is on supply and specifically how you guys are thinking about closures of refining capacity over the next several years. And the reason that I ask is because I think IEA's final tally of closures last cycle was 6 million, 7 million barrels per day of supply. And between recent closure announcements that we've seen in Asia, related factors and current refining economics, it seems like we could be on a similar track for the next couple of years as well. So I just want to see your thinking about how the supply side could be affected by this factor in coming years. And is there really any reason to believe it will be much different from the drag for the last cycle?

Doug, this is Lane. So we've always sort of had the view that really what shuts refineries down, obviously, they have to have some sort of fundamental issue, whether it's — they're configured incorrectly for where the market is or some other structural things. But ultimately, what closes them is either a big environmental — a big regulatory change where it requires a lot of capital, and it just becomes like you should look at the whole sort of scenario of cash flow. And it becomes insurmountable, and you start trying to normally try to sell and then ultimately it shuts down. The other one that does that is it could be like a big turnaround. We visited a refinery a few years ago; they put off a turnaround and had kept doing that. And ultimately, that was a big FCC and cracking complex turnaround, the cost of which got to be where it was so large, they chose to shut it down. So it's really big refineries if they can just sort of move along and manage expenses and things like that, but it's when a refinery has an outlook based on configuration or fundamentals, it makes it negative to begin with. And then they have a large cash outflow due to something changing, that's generally what gets these refineries.

The next question is from Phil Gresh of JPMorgan.

First question here, just — obviously, you've referenced the demand picture improving into July quite a bit. That said, the crack spreads are still pretty soft here in July and as we head into August. So as you look at the second half of the year and look to balance the supply against the demand and the current inventory picture, do you think demand is going to be able to take care of the inventory situation? Do you think we're in a situation where we need to underproduce through the second half of the year in a greater extent to get inventories lower?

Hey, this is Lane again. So we ultimately believe, to get back to more normalized economic sort of drivers for our business, we need to get back into sort of the 5-year range for inventories. There's three paths you talked about. There's really how does the demand look, and how disciplined are refiners with respect to their utilization rates? And then, of course, finally, it's just a matter of how many closures there are. Our view is that we've been really impressed so far with the industry's response to this in terms of being disciplined and been encouraged by that. But certainly, as we move forward, seeing how jet demand works and obviously, the seasonality with respect to butane going in the pool, we expect that utilization rates will sort of be commensurate with where the economics are. And somewhere, and then I'm going to say early next year, our view is we'll get sort of back into the 5-year range of inventories.

Okay. Got it. So I guess, with your view then just extrapolate that a little further to kind of the medium-term outlook, would you think by the middle of next year, do you think that would imply margins could get back to some kind of normalized level if demand continues to improve? Or just how are you thinking about things in terms of structurally a normalized picture moving forward?

A normalized world looks like the inventories are basically back into the 5-year band. That's how sort of — that's how we sort of look at it. And yes, we believe some more time next year, but we should be back into that sort of market.

The next question is from Sam Margolin of Wolfe Research.

So my question is about the net potential DGD expansion. You mentioned you're in engineering. At this point, the kit seems pretty well established. The underlying fundamentals of the business are good. I think what you said is reasonable that there's a high probability that in other markets that have a credit system or a carbon price that are comparable to California. So this business is growing. So I guess my question is on this evaluation, what are the inputs that you're watching? Is it more commercial? Or are you really evaluating some design changes or some other aspect of the expansion in front of FIP here?

Sam, we're really just going through our gated process and the work. This is a new location. So there's other things that you take care of, the off sites, the integration with the refinery. So it's really not — I wouldn't say — I think commercially and operationally, we feel pretty good about where we're at. It's just really doing the work you have to do to get to a cost estimate and the rigor that we apply to these things. So we're still on track. We expect to make a final investment decision in early 2021. And if we go forward, we would expect to start construction in 2021 and operations commencing in 2024.

The next question is from Doug Leggate of Bank of America.

And Jason, you're — let me add my congrats. So looks like you're jumping into the fire at a pretty interesting time. So good luck with everything.

Thank you.

Joe, at the beginning of this — at the beginning of March, when Saudi launched its flow pillar of crude to the United States, I seem to recall you talking about getting calls relating to your ability to absorb that crude. And obviously, we saw a huge increase in export or import from Saudi, essentially at the end of May. That appears to have tailed off now. And I'm just wondering if you can walk us through your prognosis for heavy availability and crude spreads in light of what I just suggested.

Yes, Doug. Gary can speak to this really well.

Yes, Doug. So I think for us, we've certainly seen spreads about as narrow as we've ever seen with our margin for light sweet, medium sour and heavy sour all right on top of each other. As we look forward, OPEC has 2 million barrels a day coming online in August. It looks like Canadian production will ramp up somewhere in the 200- to 300-thousand-barrel a day range. And so we're already starting to see that have an impact on the market. I mentioned medium sour discounts have widened about $0.60 in the last week. Canadian heavies moved about $1 a barrel weaker. Longer term, the forecast we see show that as total oil demand increases, a much larger percentage of that total oil demand will be filled with sour-type production rather than the light sweet, which came off the market. And so we think all of that could lead to wider quality differentials as we move forward longer term.

Okay. I appreciate that. I don't want to make this my second question, but just a footnote to that, Gary. Our understanding from the quality curve or associated with it at the Center for Energy Studies in Russia suggests that the increase from Saudi and Russia would be absorbed domestically. So do you believe that those barrels are actually hitting the water?

We have seen some barrels from the Basra and other sources show up in the U.S. Gulf or on offer in the U.S. Gulf, which we haven't seen in quite some time. So Basra has been an offer, which we haven't seen in quite some time. So I think some of the barrels are making their way onto the water into the market. And some of that is also due to the fact it looks like Far East buying is down a little bit as well, which is also helping to pressure the crude differentials and make our barrels available to us.

I appreciate that. So Joe, my second question, and I apologize in advance, it is a policy question in light of what we're seeing in the polls and so on. And it's really just ask you if you would mind articulating Valero's position on carbon tax, and I'll leave it there.

Okay. No, that's great. I mean — and again, we'll get Rich. Rich is responsible for our government affairs activities. We'll get him to comment on this. But Doug, we're seeing different proposals coming out, right? I mean Biden's got a position he's taken, and the House is looking at things and so on. We don't know what's going to come out of this yet, okay? We just really don't. And because nothing seems to have been settled on. But that being said, Rich, just want to kind of share what our thoughts are?

Yes. I mean, it's a little bit hard to respond to it in the abstract, right, because it all depends on how the tax is structured, right? If you're looking at a properly structured carbon tax, you've got to consider is the carbon tax going to drive carbon offshore to unregulated environment? You'll need to structure around that. It needs to be market-driven. You need to think about affordability. You need to think about complexity in structuring it, and not picking winners and losers just by virtue of it, letting it actually allow all carbon reduction options to play into the market is really important. The other thing I think you should temper all of this with is considering the state of the economy right now. I mean, any administration that gets elected is going to be dealing with a COVID recovery economy, and you need energy to drive the economy. You can't really want to drive stimulus in the economy and then layer a bunch of taxes on and completely restructure the energy format for the nation. It's really not feasible. So I think you're going to — the next administration, it's going to be about the economy, and the economy is going to need energy. And so while there's a lot of hyperbole in the campaign and a lot of aspirational statements, the reality is that they're going to need strong fuels to keep the economy going. So I guess in summary, we just need to see what they're going to do before we can say what our position would be on it.

The next question is from Roger Read of Wells Fargo.

A lot has just been hit here. But I guess one question I'll throw at you on the refining side. We've heard talk in some of the other companies about delays and deferrals on maintenance and how that may affect what's available to run, meaning maybe a little higher this fall and winter, but maybe lower next spring as people get, let's say, we get past the worst of the pandemic and all that. As you think probably, Lane, this question's for you, as you think about getting inventories back to the 5-year average, is that something that we should factor in as an additional help? Or there's enough surplus capacity everywhere if demand stays kind of soft that maybe we won't really notice anything on the maintenance deferral side?

Hey, Roger, so I think it's really a function of how that operator responds to some of this. So for example, one of the things that we did when we saw and when this all first started is we took the opportunity to have Pembroke FCC down and on its fractionator, right? So we actually incurred additional maintenance expense to deal with what we thought was an acute issue around its operation. We could have tried to get through that and get it to its turnaround next year. But we thought, you know what, let's just get and get that cleaned out and also help with this sort of the structural demand destruction that was early on. So I think it all depends on the operator. An operator who's stressed, they have their balance sheet stress or access to capital is — and debt is a little bit stressed, they may, in fact, decide to defer a lot of maintenance to some other point because they got to get through — they got a liquidity issue, and they got to get to — they got to push it out to a point at which they hope that there's enough recovery they can afford to do these things. The risk in that is that the unit, the unit doesn't really know how good your balance sheet is or how the world is. It just sort of the size. And at that point, if that unit goes down, it's an unplanned event, it becomes a much larger event. It's a much more expensive event. And that's the risk an operator in that condition has to deal with. But Valero specifically, we didn't have a lot of turnaround work going into the — even planned turnaround work in the third and fourth quarter. We'll still address where we think we have operating issues. And so — and the other general comment I'll say is, yes, we reduced expenses. One of those was, I would call it, light maintenance. You can sort of tell from the way I talk. We have just sort of a core value of ours is that we will never ever cut our maintenance capital such as it puts our reliability at risk because we believe that's a pathway to get to even higher expenses and more cash outlay in the future because we believe in being in this in the long term. So we don't operate that way, but we did touch lightly on some of what we consider to be a little bit of discretionary maintenance. So does that answer your question?

Yes, I think so. I mean, it's obviously a lot of moving parts to it. I'm just trying to, where we can, understand some of the things that are going to be coming at us here other than what...

Just what I'm trying to say is it's very operator specific. If you think — if you like to look out there, the cast of characters, the people who are in this business, some people will respond by being careful, and some people might have to take an additional risk. And then it all — and then it's just a matter of how it all unfolds.

No. I appreciate that. I guess the other question I have is to follow-up on the earlier comment about the diesel yield going from the high 30s to the low 30s as jet fuel demand comes back up. As we look overall at what's been coming in the last several weeks on the DOE is we've seen gasoline draws a little bit on net. Diesel's actually been continuing to build. Are we at a point here where jet fuel demand has recovered enough that we should see the lower diesel yields feed into no longer building diesel margins? Or kind of maybe tag teaming on Phil's question. Are we in a situation here where maybe we face, I don't know, overall run cuts or a further cut in diesel yields in order to kind of balance the market? And one of the reasons I'm asking that is as we roll late September into October, we go from summer-grade to winter-grade gasoline, and so that tends to make it easier to make gasoline. And I was just curious if that further complicates thing if we don't see a continued improvement in jet fuel demand.

Yes. So I think our view is we don't see where jet fuel demand fully recovers to where we were, and that jet fuel demand picks up and up to really correct the yield issue, which is where it gets really to Lane's point. For us to really see diesel inventories get back to that 5-year average low of total light product inventories in that 5-year average range, we really need to see discipline on the utilization. And to keep utilization down is probably the biggest key to getting inventory.

The next question is from Paul Cheng of Scotiabank.

Two questions. Since Jason is now the CFO, Jason, do you have any preliminary outlook for 2021 CapEx? If not the exact amount but whether it's going to be flat up or down comparing to this year?

Yes. Paul, hey. So we haven't given the guidance yet as you well know. But —

That's why I asked about the outlook.

So I would — I'm going to say this right now, okay? The high end would be $2.5 billion and then probably $2 billion on the low end, okay? I think we just need to wait and see what happen. Lane's got us really well positioned on the execution of the capital plan that if we need to delay a project or continue to slow some of these projects, we'll do it. I think we're very highly confident. We're just going to continue to proceed with the Diamond Green Diesel project.

We haven't slowed down now.

Yes, we're not going to slow that down. So Paul, I'd say, $2 billion. And if we see the — as guys have talked about, to get really back to a really strong margin environment, we need to see inventories come down some. That could happen sooner than later, but we just don't know. But I think to the extent we can restart some of these capital projects, we'd like to do it, okay? I think we've talked before, Jason, we've talked about this, that if you're going to prioritize your use of funds in the company, one of the first things we'd like to do is go ahead and restart these high-return capital projects like the coker, then we're going to look at the balance sheet to be sure that we reduce our debt and that we build some cash. And then ultimately, Paul, we would look at share repurchases. So anyway, that's kind of our sequencing around the use of cash.

And Jason, what is the debt level you need to bring back down to before you will consider the other maybe shareholder return options?

Bring capital down to or you saying?

No. And at that level you want to bring it down to. Because I would imagine that when you start generating free cash, maybe one of the priorities that you want to bring down your debt. Correct me if I'm wrong, but if that is the first priority, then at what point the debt level you will say, okay, wow, that we still want it to be down more so that this that we could have more balance between increasing the return to shareholders and reducing that at the same time.

Okay. Yes. Our guidance on our capital allocation framework as we target 20% to 30%. That's a good guideline. There's not an absolute hard and fast rule. That's a good thought.

But Paul, you know what kind of debt we've got out there. I mean, in the past, and we'll continue to look at it. We do regularly. But it's been prohibitively expensive for us to go out and call debt, okay? And so we look at it. And Steve looks at it all the time. It just hasn't made sense to do in the past, and we'll continue to look for going forward.

Okay. A final question for me on my side. In the event you're presented with the supply alternative, Gary, can you maybe elaborate a little bit?

So we — throughout the history, we've really supplied the Québec refinery over the water, can fully supply Québec with waterborne barrels. Line 9 is an optimization for us. It's provided a nice economic benefit to us, but we have the ability to supply Québec either West African barrels or barrels from the U.S. Gulf Coast over the water.

But is there any option or opportunity to fund additional North American supply? Or that's really what Line 9 is just that's winning that no additional well we'll be able to gain more local supply or that Calgary or that Bakken supply into that?

So the line that's really close is Line 5, and not all of Line 9 is fed from Line 5. So even if Line 5 is closed, we still believe we'd have access to Western Canadian barrels that could feed Line 9.

How does that work actually? Is it the rate? Line 5 is shut and that assumes that the total available in Line 9 become, say, call it half. Is it you will get half of your normal allocation? Or how does that work, the process?

That's close to how it would work. So there would be a progression that goes into effect based on your shipper history. And so where we would fall out on that, I'm not sure. But assuming Line 5 is half of the volume and everyone was to 50%, then would be 50% of what we normally ship through Line 9.

The next question is from Brad Heffern of RBC Capital Markets.

Joe, you've had the 40% to 50% cash return target for a long time now. I'm curious if we end up in a sort of longer margin recovery environment, maybe like we softer the financial crisis, how long you're comfortable sort of paying above that target as you are now before potentially the dividend could need to be addressed?

Okay. We'll let Jason talk generally how we're thinking about cash flows and the dividend here, okay?

You're right. We're well above it. Now I think Homer said, we're at 96% year-to-date on payout. But with this being an extraordinary and short-term event, we're not going to — we don't adjust that based on this type of a situation. So we stick with our guidance. We won't vary from it. I don't know if we have an exact number on how long we would be comfortable with that.

No, we do not.

Yes. Okay. And then, I guess, sort of along the same lines, have your thoughts changed at all about the repurchase program, just given what we've seen? I mean, obviously, the historical has been that when you have money to do repurchases, obviously, the stock price is higher. And that's certainly proven to be true this time. So is there a chance that on the other side, we see Valero with sustain a higher cash balance and a lower overall debt level than maybe we thought previously? Any color like that would be great.

So you want to talk about it or you me to? I'll tell you, it's — again, I think the key to remember here is we're in kind of a funky, short-term, what we consider to be a short-term period, okay? And we're going to evaluate it. We don't know what next week is going to hold or what the next month is going to hold or the next year. And so what we're doing is sticking to what we've done in the past, and we're comfortable with it right now. We are well positioned going into it. We've looked at how we're positioned today versus where we were back in '09 when we had a previous downturn. We stress test everything. So we're not willing right now to make decisions with long-term implications based on what we consider to be a short term set of circumstances. So we're just going to play this out. We'll see what happens.

The next question is from Neil Mehta of Goldman Sachs.

The first question I have is just on DGD margins. You've been following the indicator margins on your website. They came in a little softer than what we expected in the second quarter. Volumes looked good. But just any thoughts on 2020 DGD margins would be helpful.

Yes, Neil, I can tell you, the second quarter was $1.93 a gallon EBITDA, which we actually feel pretty good about it. If you look now where we're at relative to the second quarter, diesel price's up $0.27 a gallon. The D4 RIN component with the multiplier's up $0.12 a gallon. So you're close to $0.40 a gallon better on the indicator margin than we were in the second quarter with those components. So looking out for the rest of the year, we feel really good about where DGD is going to be for the rest of the year and foreseeable future.

That's great. And then that brings us to the follow-up. Just your thoughts on RIN and particularly the D6 RIN and just how it could play out from here and it kind of ties back into some of the election mentioned earlier?

Well, right now, we expect RINs to remain supported in the near term. There's a lot going on. You've got low energy prices relative to agricultural prices, and that makes the biofuels less competitive, which typically means a higher RIN. You've got uncertainty around the small refinery exemption program. And obviously, effects of COVID-19 on gasoline. You just don't know if you can — the gasoline pool will absorb the mandated ethanol volumes next year. So that's a risk. And then the EPA, the 2021 RVO itself has been postponed indefinitely. So there's just a lot of uncertainty around the RIN right now. So as a result, it's higher. Once we turn the corner on the pandemic, we get energy prices recovered at higher levels, we expect the RINs to drift lower.

The next question is from Chris Sighinolfi of Jefferies.

I do have two questions. I guess, first, following up on Roger's earlier question. With changes in product slate and unit configuration and perhaps the swing into winter grade, how high could you push gasoline yield if demand there continues to rebound and for jet and distillate? Maybe it doesn't? And on a related note, are you changing at all the crude procurement processes, just given the pace and degree of change and uncertainty with regard to individual product demand over the last couple of months and maybe continuing for the next couple of months?

Gasoline yield, it's probably to give you a really good answer in terms of if you were in a mode of trying to maximize gasoline and minimize distillate. It would be — it's probably in the order of 50%, low 50% sort of yields overall. In the independents, it's obviously a function of different refineries. Our Venezia refinery makes like 60% gasoline, and so it's our McKee refinery. Some of the more heavy refineries are a little bit different. So it's really a function of the refineries. And if the world works out the way, where gasoline is recovered and jet doesn't recover and consequently, you got to be careful. But we'll certainly test the limits of that probably going into probably first quarter and going into second quarter depending on again how disciplined refiners are for the rest of the year.

On crude, I guess, early in the second quarter when gasoline got very weak, we pushed a little bit more medium sour into our system to try to promote higher distillate yield. Since then we backed off, and we're in a real similar crude diet to what we typically run. And I don't see that changing in the near future.

Okay. Great. And Lane, I appreciate the early discussion of product inventories and sort of your expectations as we move into next year. For my own edification, when you think about recapturing 5-year inventory ranges and the signal that that inventory normalization might send to prices and cracks, do you think about that in an absolute sense? Or do you think about it in terms of a days of demand ratio? I know it's a conceptual question, I guess, with all this shadow inventory represented by the low refining utilization rates. I'm just curious how you and your team think about those components.

That's an excellent question. We always — because obviously, there's just different demand through time. And so it's not just — we look at where inventories are in the 5-year range. That's sort of where we start. And then we certainly start looking at days of supply. And then we look forward, are there inventories that maybe the DOE is not capturing that's somewhere else out there. And so we look at all those things, for sure. But I guess it's sort of at a high level, we're just saying there's the industry needs to be disciplined. It needs to — and obviously, demand's on its way back. We want to see what is normalized inventory to be in the 5-year range. And then we start looking at days of supply, are there inventories in unusual places that we'll take into account.

The last question today comes from Benny Wong of Morgan Stanley.

I'll keep it to one. I just want to be mindful of your time. Just kind of looking at your renewable diesel, your business margin there came in at like $1.95, which was a little bit better than what we expected. But when we look at spot prices, the business margin looks like it would be much better, maybe even close to 2.50, 2.75. When we kind of put aside movement in commodity prices is there any reasons or factors that we should not expect the same magnitude of index price recovery to flow into your business margin in 3Q and the back half of the year?

This is Martin. As I said earlier, we've seen quite a bit of recovery since the 2Q average numbers in both the diesel price and the RIN. LCFS price is flat. So I would say you ought to expect kind of what we've guided to before that we feel pretty good about third and fourth quarter for renewable diesel.

Got it. Okay. Appreciate that. So there's nothing within like movement in capture rates and costs that we might have to incrementally think upon in the back half of the year. Is that right?

That's correct.

That's all the time we have for questions today. I would now like to turn the call back to Homer Bhullar for closing remarks.

Thank you. We appreciate everyone joining us today. And if you have any follow-up questions, please feel free to call the IR team. Thank you.

This concludes today's conference. You may now disconnect your lines at this time. Thank you for your participation.