Valero Energy Corporation

Greetings and welcome to Valero's Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Homer Bouar, Vice President Invest 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 Frazier, 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 is 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 in the heart of our company. Their health, safety, and well-being remain among our top priorities and will 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 and post-shutdown, we had to make important operational and financial decisions. When the -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 -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 recover to 50% of normal. We also saw 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 98 cents 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 Alkalation Unit, which is designed to convert low-value feedstocks into a premium alkalite 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 non-discretionary 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 million, 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 the second quarter of 2020. Refining cash operating expenses of $4.39 per barrel, or $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 margin 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 US 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 partners' 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 partners' 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 -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 to 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. US Gulf Coast at 1.4 to 1.45 million barrels per day. US Mid-Continent at 380 to 400,000 barrels per day. US West Coast at 215 to 235,000 barrels per day. And North Atlantic at 375 to 395,000 barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $4.4 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 50 cents per gallon, which includes 20 cents per gallon for non-cash 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 38 cents per gallon, which includes 6 cents per gallon for non-cash 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 GNA expenses excluding corporate depreciation to be approximately $825 million. And we expect the RINS expense for the year to be between $400 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. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.

Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question today comes from Prashant Rao of Citigroup. Please proceed with your question. Good morning.

Thanks for taking the question. You bet. Hey, Joe. Good. I wanted to start on the demand recovery. Joe, you mentioned the rapid recovery 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? If you could, any color on how to think about that in terms of buckets of gasoline versus jet versus diesel and everything else?

Yeah, sure. Gary, you want to?

Yeah, sure. I'll walk you through it. 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 a 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% normal. And we've continued to see recovery as we transition into July. On the export side, as I mentioned, we bottomed out at about a 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 in 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 a third of our typical export volume in May. Just like gasoline, it's 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, which showed July export volumes, 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 a third of what our refineries produced, the diesel they produced. July of this year, with our estimate on exports, it would be 47%. So almost half of what our refineries are making are going to the export markets. On the jet side, we can also see 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. Thank you for all that color, Gary. My follow-up is just on the balance sheet. You've met that the 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 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?

Yeah, why don't we let Jason take a shot at

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

Okay, fantastic. Thank you both, 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, Prashan.

The next question is from Teresa Chen of Barclays. Please proceed with your question.

Good morning. Thanks for taking my question. Just a quick follow-up on Prashan's question related to the demand side and your commentary about Latem. The current estimates of, I think it was 107% versus normalized levels that you're seeing, how much of that do 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?

Yeah, 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 of demand recovery we're seeing in the United States. I do think you may have some pre-filling 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. 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 pipelines 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? Do you think that could create perhaps a pull on Cushing? What are your thoughts here?

Yeah, 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, and they'd had some efforts to improve their capacity to help clear the Bakken. Of course, through that Enbridge system, we are connected via our Line 9 to Quebec, so we'd have an opportunity to bring that Bakken volume to Quebec, 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 TI probably is in that $2 to $3 range based on the incremental cost to the Galt and clear.

Understood. Thank you very much, and congratulations to Jason as well.

Thank you.

The next question is from Manav Gupta of Credit Suisse. Please proceed with your question.

Hey guys, first is a more of a policy question at this point. Hey Manav, we can barely hear you,

man. Sorry.

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 force 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 Walsh take a shot at the answer, okay?

You know, so we have some familiarity with Biden and some of his priorities, and one of the things I would point out is that nobody is 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 the 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 you know, there's a big marketplace for renewable diesel, and we think it fits strongly in the green agenda. Martin, anything you want to add to

that? Well, I would just echo that. When you look at the, when you get the true numbers, if you look at the carbon intensity, renewable diesel competes very well with a so-called zero emission vehicle. You're already up to 16, 18 percent 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, you know, globally as in the fuel mix for a long time to come.

So that was a helpful one quick follow-up. So the Monday morning 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 effective 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?

You know, probably the biggest variance is due to the crude differentials. So, you know, the crude differentials had been very tight, but we've seen medium sours move 60 cents in the last few days and we've seen the Canadian heavy move a dollar. And so, you know, in 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.

Thank you so much for taking my

question. The next question is from Paul Fanky of Hubbard. Please proceed with your question.

Good morning, everyone. Can you hear me? Hi,

Paul.

Yeah, it's Analyst Hub, actually, not Hubbard. But anyway, good to speak to you all. Joe, it's been I was wondering the extent to which you feel the world has changed on a secular basis. Obviously, you've referred to the demand side and we can debate, you know, how air travel and, you know, whether suburbanization is more gasoline-intensive. But, you know, clearly you've accessed capital, you seem 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 laugh about how the election may change things. But any further comments you have on that would be very interesting. Thanks, Joe.

Yeah, you bet. You know, Paul, I mean, looking back over the last six months, it's been a bit of a roller coaster ride. And we started off the year in pretty decent shape. And then we had the incredible trough. You know, most of us in this room have been in this business for a very long time. And, you know, you got to look back a lot of quarters before you see a quarter like the second quarter of this year. And 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, you know, 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've lived over the last quarter. So anyway, I'll stop there. Gary, talk a little bit about the crude situation.

Yeah. So I think most forecast we 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 US will still be a net exporter of crude oil. And as long as the US is exporting crude oil, we'll continue to have advantage on the light sweet barrels we're bringing into our system. And of course, with the flexibility that we have, especially with our complex Gulf Coast reclining assets, getting some more medium and heavy salar barrels on the market will help us as well from that aspect.

And then as far as your answer, no, Paul, and you mentioned the election, you know, 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 know, you can have a lot of conversation around what we're going to do and what needs to be done. But in reality, fossil fuels are going to be with us for a very long time. And demand forecasts continue to be or increase crude oil consumption going forward as countries continue to develop and so on. So we just need to not get hung up in the, you know, I think we're going to be in this dungeon that we're in now forever.

Yeah, I mean, you know, 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 that we've just printed minus 30% GDP and we've got yesterday gasoline demand down 8%, it's actually quite incredible. Thank you. Take care.

The next question is from Doug Tarason of Evercore ISI. Please proceed with your question.

Good morning, everybody. Hey, Doug. 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 six, seven million barrels per day of supply. And between recent closure announcements that we've seen in Asia, IMO 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 just want to see how you're thinking about how the supply side could be affected by this factor in coming years. And is there really any reason to believe it'll be much different from the drop in the last cycle?

Hey, Doug, this is Lane. So, you know, 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 a they're configured incorrectly for, you know, where the market is or some other structural things, but ultimately what closes them is either a big environment, big regulatory change where it requires a lot of capital. And it just becomes like you look at the whole sort of scenario of cash flow and it becomes remountable and you start trying to normally try to sell it and then ultimately it shuts down. The other one that does that is it could be like a big turnaround. We visited a refinery few years ago back in the UK and that's essentially what got them. They had a they'd put off a turnaround and had kept doing that. And ultimately that it was a big SEC, Alky cracking complex turnaround, the cost of which got to be where it was so large, they chose to shut it down. So let's it's really big, you know, refineries, if they can just sort of kind of move along and expenses and things like that. But it's when the refinery has an outlook based on configuration or fundamentals, it makes it negative to begin with. And then they had there's a large cash outflow due to some something changing. That's generally what what gets these refineries. Okay, thanks

a lot.

The next question is from Phil Gresh of JP Morgan. Please proceed with your question. Hi, yes. Hey, good morning.

First question here just, obviously you've referenced the demand picture improving into July quite a bit. You know, 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 in the current inventory picture, do you think demand is going to be able to take care of inventory situation? Do you think we're in a situation where we need to under produce through the second half of the year? You know, in a greater extent to get inventories lower?

Hey, this is Lane again. So you know, we ultimately we believe to get back to more normalized economic sort of drivers for our business, we need to get back into sort of the five year range for inventories. There's three paths you talked about, there's really is it what does the demand look and how disciplined are refiners with respect to their utilization rates and then, you know, of course finally it's just a matter of how many closures there are and you know, 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 you know, somewhere it's you know, somewhere and then, you know, I'm going to say early next year we our views will get sort of back into the five year range of inventories.

Okay, got it. So I guess would your view then just extrapolating that a little further to kind of the medium turnout look, would you think by the middle of next year you think that would imply margins could get back some kind of normalized level if demand continues to improve or just how do you think about things in terms of structurally a normalized picture moving forward?

You know, a normalized world looks like the inventories are basically back into the five year band. That's how, you know, sort of that's how we sort of look at it and you know, we believe some more time next year or we should be into that sort of market.

Okay,

all right, thank you.

The next question is from Sam Margolin of Wolf Research. Please proceed with your question.

Morning everybody. Thanks for taking the questions. So my question is about the next potential DGD expansion. You know, you mentioned you're in engineering, but at this point, you know, 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 the other markets that have a credit system or a carbon price that are comparable to California. So this is growing. So I guess my question is on this evaluation, you know, what are the inputs that you're watching more commercial or are you really evaluating some design changes or some other aspect of the integration, you know, in front of FIP here?

Hey Sam, this is Martin. We're really just going through our gated process and the work, you know, this is a new location. So there's other things you have to take care of the offsides, the integration with the refinery. So it's really not, I wouldn't say I think commercially and operationally, you know, 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, you know, we're still on track or, you know, 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.

Okay. I appreciate it.

Thanks, Sam. The next question is from Doug Leggett of Bank of America. Please proceed with your question.

Thanks. Good morning, everybody. Hope everybody's doing well out there. Jason, you're, can you add my congrats? It looks like you're jumping into the fire at pretty interesting times. So good luck with everything. Joe, at the beginning of this, at the beginning of March, when Saudi launched its flotilla of crude to the United States, I seem to recall you talking about getting calls relating to, you know, your ability to absorb that crude. And obviously we saw a huge increase in exports or imports rather 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.

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

Yeah, Doug. So I think, you know, 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, you know, 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 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 60 cents in the last week. Canadian heavies moved about a dollar a barrel weaker. Longer term, you know, 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 our colleague or associate with the years of the Center of Energy Studies in Russia, he suggested that the increase from Saudi and Russia would be absorbed domestically. So do you believe that those barrels are actually hitting the water?

You know, we have seen some barrels from the Middle East show up in the US Gulf or on offer in the US Gulf, which we haven't seen in quite some time. So Basra has been on offer, which we haven't seen in quite some time. So I think some of the barrels are making their way onto the water and to 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 the barrels available as.

I appreciate that. So Joe, my second question, 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, I ask you if you would mind articulating Valero's position on carbon tax and I'll leave it there.

Thanks. Okay, no, that's great. You know, I mean, again, we'll get Rich Walsh. Rich is responsible for our Government Affairs activities. We'll get him to comment on this. But, you know, 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.

Yeah, 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 got to consider, you know, is the carbon tax going to drive carbon offshore, you know, to unregulated environments? 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, you know, 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, you know, hyperbole in the campaign and a lot of aspirational statements, the reality is 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.

Understood. I appreciate you framing it. We should have you think about it. Thanks a lot, guys. Good luck.

Thanks. The next question is from Roger Reed of Wells Fargo. Please proceed with your question.

Hey, good morning, everybody.

Hi, Roger.

A lot of stuff's 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, you know, what's available to run, meaning maybe a little higher this fall and winter, but maybe lower next spring as people get, you know, 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, you know, getting inventories back to the five-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, you know, 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 when this all first started is we took the opportunity to take Enbrook FCC down and put down 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 you know what? Let's just get in and get that cleaned out and also help with this sort of just the sort of structural demand destruction that was, you know, early on. So I think it all depends on the operator. An operator who's stressed, they have their balance sheet stress, their access to capital is, you know, 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 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 doesn't really know how good your balance sheet is or how the world is. It just sort of decides. 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. At Valero specifically, we didn't have a lot of turnaround work going into this or even plan turnaround work in the third and fourth quarter. We'll still address where we think we have operating issues. And so in the other general comment I'll say is, yeah, we reduced expenses. One of those knobs was I would call it light maintenance. You can sort of tell from the way I talk, we have a, you know, just sort of core value of ours is that we will never ever cut our maintenance capital such that 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, you know, touch lightly on some of what we consider to be a little bit of discretionary maintenance. So does that answer your question?

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

it's very, you know, it's very operator specific. If you think, if you'd like to look out there, the cast of characters, the people who are in this business, you know, some people respond by being careful and some people might have to take an additional risk and then it all, 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, you know, what's been coming in the last several weeks on the DOEs, we've seen, you know, gasoline draws a little bit on net, diesel's actually been continuing to build. Are we at a point here where, you know, jet fuel demand is recovered enough that we should see lower diesel yields feed into no longer building diesel margins or kind of maybe tag teaming on Phil's question? Are we at 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, you know, as we roll late September into October, we go from summer grade to winter gasoline. And so that tends to make it easier to make gasoline. And I was just curious if that further complicates things if we don't see a continued improvement in jet fuel demand.

Yeah, 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 enough to really correct the yield issue, which is where it gets really to Lane's point. For us to really see diesel -to-end to get back to that five-year average, total light profit in the five-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.

So stay tuned. All right, thanks, guys.

The next question is from Paul Chang of Scotiabank. Please proceed with your question. Hi,

good morning,

guys.

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

Yeah, Paul, hey, so we haven't given the answer yet, as you well know. That's

why I say anything memory, I will not know.

So I'm going to say this right now, okay? The high end would be two and a half billion, and then probably two billion on the low end, okay? I think we just need to wait and see what happens. 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. Yeah, we haven't slowed that down. Yeah, we're not going to slow that down. So Paul, I'd say two billion. And if we see, as the 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 if to the extent we can restart some of these capital projects, we'd like to do it. Okay? And I think we've talked before, Jason, we've talked about this, that if you're going to prioritize your use of funds into a company, one of the first things we'd like to do is go ahead and restart these high return capital projects like the Cobra. Then we're going to look at 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? Actually, just curious. Here is Joe 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, are you saying? No, and then what

debt level you want to bring it down to? Because I 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 that level, you will say, okay, while we still want it to be down more, but at this level, that means we could have more balance between increasing the return to shareholder and reducing debt at the same time.

Okay. Yeah, I know our guidance on our capital allocation framework is we target 20 to 30%. So 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, you know, we look at it, Jason Steen looks at it all the time. It just hasn't made sense to do in the past and we'll continue to look forward, going forward, at it going forward.

Okay. A final question from me. Yes. Yes. Gary, can you maybe elaborate a little bit?

Yes. So, you know, we do have history. We really supplied the Quebec refinery over the water and can fully supply Quebec with waterborne barrels. You know, Line 9 is an optimization for us and provided a nice economic benefit to us, but we have the ability to supply Quebec either West African barrels or barrels from the U.S. Gulf Coast over the water.

But is there any option or opportunity to find additional law of American in-land supply or that that's really one Line 9 is such that that's really that's no additional route would be able to get more local supply or that the Calgary or that can supply into that.

So the line that's really closed 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.

So how does that work actually? Is it a prorated? If Line 5 is shut and that's assumed that the total available in Line 9 becomes say called yet 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 proration that goes into effect based on your shipper history. And so where we would fall on that, I'm not sure. But you know assuming Line 5 is half of the volume and everyone was prorated to 50 percent, then we would be 50 percent of what we normally ship through Line 9.

That's it.

Thank you.

Thanks Paul. The next question is from Brad Heffern of RBC Capital Markets. Please proceed with your question.

Hey everyone. Thanks for for taking the questions. You know Joe, you've had this 40 to 50 percent cash return target for a long time now. I'm curious if you know we end up in a sort of longer margin recovery environment maybe like we saw after the financial crisis. How long you're comfortable sort of paying above that target as you are now before potentially the the dividend could need to be addressed?

Okay hey we'll let Jason talk generally to how we're thinking about you know cash flows and

the dividend here okay? Yeah you're right. You know we're well above it now. I think Homer said we're at 96 percent year to date on payout. But with this being an extraordinary and short-term event, you know we're not going to we don't adjust that based on on this type of a situation. So we stick with our guidance. We will vary from it. I don't know if we have an exact number on how long we would be comfortable with that. No we don't.

Yeah 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 the historical criticism 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 cash balance and a lower overall debt level than maybe we thought previously? Any color like that would be great.

Thanks. So you want to talk about or you want me to? Oh cool. You know 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's going to hold or next month's 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. You know we've looked at how we're positioned today versus where we were back in 2009 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 and we'll see what happens.

Okay fair enough Joe.

Thanks. The next question is from Neil Mehta of Goldman Sachs. Please proceed with your question.

Good morning team and thanks for taking the question. The first question I have is just on EGB margins. You've been following the indicator margins on your website. They came in a little faster than we expected in the second quarter. The following looks good. But just any thoughts on 2020 EGB margins would be helpful.

Yeah Neil this is Martin. I can tell you you know the second quarter was a dollar ninety three a gallon EBITDA which we actually feel pretty good about. If you look now where we're at relative to the second quarter diesel price is up 27 cents a gallon. The D4 RIN component with the multipliers up 12 cents a gallon. So you know you're close to 40 cents 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 that brings us to the sixth RIN and just how it could play out from here and it kind of ties back into some of the election comments here you guys made earlier.

Well you know 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 refiner 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. You know once we turn the corner on the pandemic we get lower energy prices and energy prices excuse me recover to higher levels we expect the RINs to drift lower.

The next question is from Chris of Jeffreys. Please proceed with your question.

Hi Joe. Good morning everybody.

Hi

Chris. Thanks for the added color today. I do have two questions. I guess you know first following up on Roger's earlier question with changes in product slate and unit configuration and perhaps the swing in the 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 you know the pace and degree of change and uncertainty with regard to individual product demand over the last couple months and maybe continuing for the next couple months?

Gasoline yield you know 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 you know it's probably in the order of a 50% low 50% sort of yields overall. In any case it's obviously a function of different refineries you know our Benicia refinery makes you know like 60% gasoline and so does our key 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 you know this is where gasoline's recovered and jet doesn't recover and consequently you got to be careful we'll certainly test the limits of that probably going into probably first quarter and going in the second quarter depending on again how disciplined refiners are for the rest of the year.

You know crude I you know 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 history. 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 you know 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 five-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 but I guess with all this shadow inventory represented by you know the low refining utilization rates I'm just curious how you and your team think about those components.

That's an excellent question you know we always because you know obviously there's just different demand through time and so it's not just you know we look at we look at where inventories are in the five-year range that's sort of where we start and then we certainly start looking at days of supply and then we look for is 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 you know I just it's sort of a at a high level we're just saying you know there's the industry needs to be disciplined it needs to and there's and obviously demands on its way back but we want we want to see you know what is normalized inventories to be in the five-year range and then then we start looking at days of supply and are there inventories and unusual places that that we'll take into account.

Okay that's really helpful thanks a lot guys good luck.

The last question today comes from Benny Wong of Morgan Stanley please proceed with your question.

Hey good morning guys thanks for squeezing me in. 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 a dollar 95 which was a little bit better than what we expected but when we look at spot prices the midget the business margin looks like it'd be much better maybe maybe even closer to 50 to 75. Will we kind of put aside movement in commodity prices is there any reasons or factors that we not expect the same magnitude of index price recovery to flow into your your business margin and 3Q and the back half of the year?

Okay this is Martin you know as I said earlier we've seen quite a bit of recovery since the 2Q average numbers in both the diesel price and the ren 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.

Okay appreciate that so there's nothing within like movements and capture rates and costs that we might have to incrementally think about in the back half of the year is that right? That's correct. Great thank you very much. Thanks Betty.

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