Greetings and welcome to Valero Energy Third 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. The operator will provide instructions for the question-and-answer session. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President of Investor Relations. Thank you sir, you may begin.

Good morning everyone and welcome to Valero Energy Corporation's third 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 investor.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 will turn the call over to Joe for opening remarks.

Thanks Homer and good morning everyone. The third quarter was another challenging period in which refining margins continue to be pressured by pandemic-imposed restrictions on global economies. These restrictions have limited individual movement and in-person activities across the globe, resulting in lower demand for finished refinery products. This in turn has created less incentive to produce crude oil and has led to narrower crude oil discounts compared to last year. Despite this challenging environment, there were a number of positive developments from the previous quarter, as product demand increased with incremental easing of restrictions on businesses, and the reopening of some schools. Relative to the second quarter, DOE statistics show the gasoline, diesel and jet demand improved by 25%, 7% and 57% respectively, which is in-line with the increase in demand that we experienced across our system. Our wholesale volumes remain steady, moving over 50% of our total light products production. Our gasoline and distillate exports to Latin America and Europe were also robust in the third quarter. We exported 316,000 barrels per day in the third quarter, which is significantly higher than the 170,000 barrels per day we exported in the second quarter. We also saw a steady increase in our wholesale volumes into Mexico, where we have been proactively expanding our logistics network for the last several years. In fact, Valero is now one of the largest private fuel importers into Mexico. With the incremental easing of restrictions and higher product demand, our refinery utilization increased from 74% in the second quarter to 80% in the third quarter and we increased our ethanol plant production as well from 49% to 81% of capacity. Our low-carbon renewable diesel business remains resilient, with another quarter of solid performance, realizing a margin of $2.72 per gallon and setting a record for sales volumes. In addition, we remain well capitalized. We ended the quarter with over $4 billion of cash and almost $10 billion of total available liquidity. While we expect margins to improve as economies continue to reopen and product inventories come down to normal levels, we opportunistically raised another $2.5 billion of debt at very attractive rates to ensure that we're able to keep our high-return projects on track and to honor our commitment to shareholders, even if the current low-margin environment persists for longer than currently anticipated. Turning to capital investments, we continue to execute on announced projects that are expected to drive long-term earnings growth. The St. Charles Alkylation Unit, which is designed to convert low-value feedstocks into a premium alkylate product, remains on track to be completed in the fourth quarter. 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. We're also evaluating a number of other low-carbon growth projects that are in the development phase of our gated process. Now, we continue to strengthen our long-term competitive advantage with investments in our renewable diesel business. The Diamond Green Diesel expansion project at St. Charles, which is designed to increase renewable diesel production capacity by 400 million gallons per year to 675 million gallons per year is still expected to be completed in 2021. Diamond Green Diesel also 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 refinery. As we look ahead, we expect to see improvement in margins, as product inventories approach the normal five-year range. U.S. gasoline inventory is already in the middle of the five-year range. And although distillate inventory is higher than the five-year range, it's been trending downwards in recent weeks. Diesel demand should continue to improve, supported by winter heating oil demand and harvest season. Oil refinery turnarounds coupled with recently announced and anticipated closures or conversions of less advantaged refineries should also further balance supply. Although there is a lot of uncertainty in the market, we remain steadfast in the execution of our strategy, pursuing excellence in operations, investing in earnings growth with lower volatility and honoring our commitment to stockholder returns. Our unmatched execution, while being the lowest cost producer and ample liquidity, position us well to manage this pandemic-induced low-margin environment and maintain our position of strength as the global economy recovers. Lastly, the guiding principles underpinning our capital allocation strategy remain unchanged. There is absolutely no change in our strategy which prioritizes our investment-grade ratings, sustaining investments and honoring the dividend. So with that, Homer I'll hand the call back to you.

Thanks Joe. Before I provide our third quarter financial results summary, I'm pleased to inform you that we recently posted a Sustainability Accounting Standards Board or SASB Report on our website that aligns with the SASB framework for refining and marketing industry standards. As you'll see in our report, we are targeting to reduce and offset greenhouse gas emissions by 63% by 2025 through investments in Board-approved projects. The targets will be achieved through absolute emissions reductions through refining efficiencies, offsets by our ethanol and renewable diesel production and global blending and credits for renewable fuels. This is consistent with our strategy as we continue to leverage our global liquid fuels platform to expand our long-term competitive advantage with investments in economic low carbon projects. And, now turning to our quarterly performance, we incurred a net loss attributable to Valero stockholders of $464 million or $1.14 per share for the third quarter of 2020 compared to net income of $609 million or $1.48 per share for the third quarter of 2019. The third quarter 2020 adjusted net loss attributable to Valero stockholders was $472 million or $1.16 per share compared to adjusted net income of $642 million or $1.55 per share for the third quarter of 2019. Third quarter 2020 adjusted results primarily exclude the benefit from an after-tax lower of cost or market, or LCM, inventory valuation adjustment of approximately $250 million and an after-tax loss of $218 million for an expected LIFO liquidation. For a full reconciliation of actual to adjusted amounts, please refer to the financial tables that accompany the release. The refining segment reported an operating loss of $629 million in the third quarter of 2020 compared to operating income of $1.1 billion in the third quarter of 2019. Excluding the LCM inventory valuation adjustment, the expected LIFO liquidation adjustment and other operating expenses, third quarter 2020 adjusted operating loss for the refining segment was $575 million. Third quarter 2020 results were impacted by narrow crude oil differentials, lower product demand and lower prices as a result of the COVID-19 pandemic. Refining throughput volumes averaged 2.5 million barrels per day, which was lower than the third quarter of 2019 due to lower product demand. Throughput capacity utilization was 80% in the third quarter of 2020. Refining cash operating expenses of $4.26 per barrel were $0.21 per barrel higher than the third quarter of 2019, primarily due to the effect of lower throughput rates. Operating income for the renewable diesel segment was $184 million in the third quarter of 2020 compared to $65 million in the third quarter of 2019. After adjusting for the retroactive Blenders Tax Credit, adjusted renewable diesel operating income was $123 million for the third quarter of 2019. Renewable diesel sales volumes averaged 870,000 gallons per day in the third quarter of 2020, an increase of 232,000 gallons per day versus the third quarter of 2019, due to the effect of the planned maintenance that occurred during the third quarter of 2019. Operating income for the ethanol segment was $22 million in the third quarter of 2020 compared to a $43 million operating loss in the third quarter of 2019. The third quarter 2020 adjusted operating income for the ethanol segment was $36 million. Ethanol production volumes averaged 3.8 million gallons per day in the third quarter of 2020, which was 206,000 gallons per day lower than the third quarter of 2019. The increase in operating income from the third quarter of 2019 was primarily due to higher margins resulting from lower corn prices. For the third quarter of 2020, G&A expenses were $186 million and net interest expense was $143 million. Depreciation and amortization expense was $614 million and the income tax benefit was $337 million in the third quarter of 2020. The effective tax rate was 47%, which was primarily impacted by an expected U.S. federal tax net operating loss that will be carried back to 2015, when the U.S. federal statutory tax rate was 35%. Net cash provided by operating activities was $165 million in the third quarter of 2020. Excluding the favorable impact from the change in working capital of $246 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 used by operating activities was $177 million. With regard to investing activities, we made $517 million of total capital investments in the third quarter of 2020, of which $205 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $312 million was for growing the business. Excluding capital investments attributable to our partners, 50% share of Diamond Green Diesel and those related to other variable interest entities, capital investments attributable to Valero were $393 million. Moving to financing activities, we returned $399 million to our stockholders in the third quarter of 2020 through our dividend, resulting in a year-to-date total payout ratio of 165% of adjusted net cash provided by operating activities. With respect to our balance sheet at quarter end, total debt and finance lease obligations were $15.2 billion and cash and cash equivalents were $4 billion. The debt to capitalization ratio, net of cash and cash equivalents was 36%. At the end of September, we had $5.8 billion of available liquidity excluding cash. Turning to guidance, we expect approximately $2 billion in capital investments attributable to Valero for 2020; about 60% of our capital investments is allocated to sustaining the business and 40% to growth. We expect our annual capital investments for 2021 to be approximately $2 billion as well, and approximately 40% of our overall growth CapEx for 2020 and 2021 is allocated to expanding our renewable diesel business. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.41 million to 1.46 million barrels per day; U.S. Mid-Continent at 385,000 barrels to 405,000 barrels per day; U.S. West Coast at 230,000 barrels to 250,000 barrels per day; and North Atlantic at 400,000 barrels to 420,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.35 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be 750,000 gallons per day in 2020, which reflects planned maintenance in October. Operating expenses in 2020 should be $0.45 per gallon, which includes $0.17 per gallon for non-cash costs, such as depreciation and amortization. Our ethanol segment is expected to produce a total of 4.2 million gallons per day in the fourth quarter. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the fourth quarter net interest expense should be about $155 million and total depreciation and amortization expense should be approximately $590 million. For 2020, we expect G&A expenses excluding corporate depreciation to be approximately $775 million, which is $50 million lower than our prior guidance. 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 beneficial tax provisions in the CARES Act, as well as the COVID-19 pandemic and its impact on our business, we're 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.

The operator will now open the call to questions. Our first question comes from the line of Phil Gresh with JPMorgan. Please proceed with your question.

Just wanted to start off by asking a bigger picture question around how Valero thinks about capacity management. Obviously recognizing Valero is at the low-end of the cost curve. The guidance here for 4Q and the results of past few quarters, you've had utilization in the low '80s roughly. So I'm just curious how philosophically you think about managing capacity, whether it's from a temporary perspective or from a permanent perspective. Just what are the decision points to think about? Or is it more just managing, say, secondary units, given the situation with diesel is more challenging than gasoline are, just any thoughts you'd have would be helpful. Thank you.

All right. So, good morning Phil. This is Lane. I'll start by answering it on the near-term: the way Valero looks out and how we've been running our system is trying to optimize at a lower utilization level, being very selective on the crudes we run and making sure we have the molecules where we want them. Certainly it's a challenging time to do that; you just have to be very careful. We've seen our ability to flex our refinery yields quite a bit when running at lower utilization. You can do a lot of that; we've seen movement in gasoline yield. Distillate yields can move up or down roughly 10%, which is a little different than when you're at full utilization. So in the near-term, you're constantly trying to optimize your operations, obviously to preserve cash flow here. Longer-term, as I've spoken about in earlier calls, when a company like Valero looks at an asset to decide whether to run through or not, it's largely driven by a change in trade flows. What I mean by that is you see significant crude advantage changes or something has changed in product markets that fundamentally alters gross margin competitiveness, and that combined with a big regulatory spend or required CapEx are really the things that drive a company to consider refinery closure. When you think about that criteria, you see that in the U.S. on the West Coast and the East Coast, and you've seen companies make those decisions. Europe is another example where refineries bring crude oil in and have to export a lot of product; that's a tough situation if you don't have a structural advantage on OpEx. That's sort of my answer on that.

The second question would just be around the third quarter results themselves. Obviously, in the prepared remarks, Joe, you talked about tighter crude differentials as a factor that drove the sequential capture rate declines, particularly in the Gulf Coast and Mid-Continent. But I was just curious, are there any other one-time factors in the quarter? I'm thinking perhaps multiple hurricanes on the Gulf Coast as one that might have led to a more challenging performance versus what you would maybe ordinarily thought of?

Good question, Phil. Lane will take a crack at this and then Gary can follow on.

Yes. So you're correct. Our Port Arthur refinery had to be shut for a period, and our ability to come back up was impeded by the utility provider, which was hit very hard. So it's regional—the utility provider had a difficult time providing power. They did a great job recovering, but ultimately that slowed our ability to bring the refinery back up. So we had some volume variance at that refinery and that contributed to the quarter's results.

Yes, the only thing I'll add is, as you know, we provide ourselves a space in the U.S. Gulf Coast system on our ability to optimize and really well define a lot of these disadvantaged or discounted feedstocks. Those opportunities really just weren't there in the third quarter and that certainly impacted our Gulf Coast operations.

Okay. Great, thank you.

Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

Joe, in your prepared remarks, you had indicated that the renewable diesel margin for the quarter was about $2.72. And in the last quarter this number was $2.22. So there was almost a $0.50 increase quarter-over-quarter. And when I look at the renewable diesel margin indicator you provide every week, which is very helpful, that was indicating a $0.01 improvement. So if you could help us sort of square out a little as to how that $0.01 in indicator margin actually translated to over $0.50 in actual capture for the renewable diesel business segment?

Good morning Manav. Listen, I'll let Mark take a crack on that one.

So in the indicator margin, as you know, it is a proxy for feedstock using the soybean oil price, and we're obviously not paying soybean oil price for feedstocks when we use waste feedstocks. So that fluctuates quite a bit, Manav. That's the biggest reason — the actual feedstock versus the soybean oil proxy can vary substantially, and that explains most of the difference.

Okay. And then quick follow-up: I'm sure you have already secured feedstocks for the St. Charles expansion. But again, there are a number of announcements out there. So are you already in the process of securing more feedstock for Port Arthur, if you could help us out there a little?

Well, I think the backdrop is there are a lot of announcements out there and time will tell. If you look back historically, there's always been a lot of announcements and many projects never came to fruition. Will it be different this time? It may be somewhat different. But you know, we're just confident in our ability to source waste feedstock going forward. Waste feedstock supply is tied to global GDP growth and our partnership with Darling gives us the benefit of vertically integrated access to low-cost, low-carbon intensity feedstocks. We also get the benefit of Darling's experience in the global feedstock markets. Darling also helps us procure feedstocks from other suppliers. So we just feel like we have a unique position here and that's going to allow us to maintain these superior margins versus the competition.

Our next question comes from the line of Theresa Chen with Barclays. Please proceed with your question.

I guess a follow-up question on the renewable diesel front. And clearly the energy transition is a big theme along with ESG investing, happy to see the additional disclosures consistent with the SASB framework. Can you talk about how you view your renewable diesel position as far as the defensibility of your projected return? How many of these projects that have been recently announced are you factoring in as likely to come to fruition? And also on the LCFS prices as well, do you see any risk there?

Sure, I'll take a stab at that. This is Martin. Obviously we keep track of all the announced projects. We also keep track of all the new policies that are coming and what we expect to come. It's cloudy — the farther you go out the cloudier it gets. You're making projections here. But if you step back and look at where we're at, a lot of these projects aren't going to get built. That's just a fact. And you've got more policies coming. Right now you've got California, you've got RED II in Europe, then you've got British Columbia and Ontario in major markets. Oregon's ramping up. We're going to have a nationwide clean fuel standard in Canada. Sweden, Norway, Finland are being more aggressive. You also have the state of Washington moving forward and a number of Midwest states and Colorado announcing policies too. The biggest one though is New York, where the preliminary information they put out has a lot of renewable diesel in the plan. So we really feel good about the demand. Renewable diesel as a molecule is a drop-in fuel, it's low carbon intensity and there is no blend wall. If you take California, they've hit the brakes a few times when low carbon wasn't available — they slowed down the program; if it is available I would expect these regulators to hit the accelerator. So at the end of the day, all that being said, is there advantage to first mover? Yes, I would think so, and we're the first mover in the United States and we feel really good about our position and what we've laid out to do.

Understood. And Joe, related to your statements about the other low carbon growth projects under development, can you give us a flavor of what kind of projects these are? Are you talking about additional investment in biofuels and is hydrogen related work part of this — any color you can share there?

Yes. What we're really looking at right now is carbon sequestration projects largely, and really trying to tie those to the markets Martin was talking about. This is where we think we can make investments to lower the carbon intensity of fuels and make them more competitive for these markets.

Your next question comes from the line of Brad Heffern with RBC Capital Markets. Please proceed with your question.

So you made it pretty clear from the remarks and the press release and your remarks on the call that there is no change to the capital framework or the dividend part. I think you said in your prepared remarks even if this COVID weakness goes on for longer than expected. Can you add a little more color around that? If we see four more quarters of less than negative $1 EPS, do you still see everything being unchanged or what point do you have to re-evaluate how you think about it? Thanks.

Yes Brad, that's a good question. Let me give Jason some room to answer and then I'll follow on.

Yes, this is Jason. We basically feel we're a long way from rethinking the dividend. At the end of September, we had a little over $4 billion in cash and about $5.7 billion of liquidity available under our committed facilities. We saw positive signs in the third quarter: demand improved, export volumes picked up. So we think things are headed in the right direction. It's just a question of how fast. The course of a vaccine would really accelerate things alone. Looking bigger picture, this pandemic is an isolated event. We're very reluctant to revise our long-term capital allocation framework that has served us well for so many years. With our cash and liquidity position and the way things appear to be headed right now, we just don't think adjusting the dividend is a step we're going to need to take.

Yes, let me just add to this. There has been a lot of question out there regarding the dividend. I've been in this job a little over six years now, and when we came out with the capital allocation framework and our approach to rewarding shareholders at that time, we have done nothing but execute on that plan. We've been very clear in our communications and we've demonstrated our commitment to our owners and we're going to continue to do that. I think one needs to decide whom they're going to listen to and who really understands what's going on. There are management teams that demonstrate their commitment to shareholders for years and there are others taking positions from a basis of very little knowledge. That can create pressure and volatility that affects our long-term shareholders. So anyway, I would encourage everyone to listen to our consistent messaging. I think we've been pretty clear at this time and Jason's answer was exactly right.

And then maybe for Lane or Gary. Just on the West Coast, obviously as part of the renewable diesel discussion, we've seen a couple of closures out there. I know historically you've thought about that market as sort of being an option value market for Valero. Do you think on the other side of all this COVID disruption that it's potentially a stronger market that's less like option value? How do you see that playing out?

This is Lane. I would say we're always going to manage it by being very careful about what we send to market, but we certainly believe ultimately COVID will pass and gasoline and diesel demand will recover and that will change the balances out there. So in the near term, it looks like an improved market. Strategically we don't view the West Coast as non-core; we intend to manage it carefully and take advantage of near-term opportunities as they arise.

Our next question comes from Prashant Rao with Citigroup. Please proceed with your question.

My first one is on the balance sheet. Jason, I wanted to ask a couple of follow-ups here. Given the inventory adjustments, the LIFO liquidation and the liquidity management you've done, I wanted to focus on balance sheet cash and cash equivalents that you need to keep on hand for working capital in the current environment. Is that lower now going forward? I know we used to think about it as slightly under $2 billion for balance sheet cash needs — is that slightly lower now and does that give you a little room under the collar as we think about managing through the next couple of quarters into the recovery?

We still target to be in that range. I think that's still a good assumption.

Yes, clearly as we go forward one of the things we did is take advantage of opportunities in the debt markets. And as Lane spoke about earlier, the supply chain has changed, and so the working capital and inventory volumes that we need are different than they were in the past. We took the P&L impact this year, but we run our business to target proper operating levels for all of our inventories. That's what guides us; it's not so much that we need to take a LIFO impact — it's about the proper operating level for our inventories and we adjusted to that. And so we've seen some benefit from the cash side.

Okay, thank you. I had another question on macro-specific products on jet fuel. We're trying to get our arms around what would happen with a slower jet demand recovery. What does that look like for refining margins and how does the system cope with that if it takes a few more years to get back? In a bear case scenario, if jet fuel demand stays lower for longer — say 70% or 80% of typical demand — at what level is that really not that much of a headwind? Little bit of color on how to think about that and where we can think about it stopping pressure on distillate inventories, not just in your system but overall globally?

So overall, I think you could see we have full flexibility to pretty much reduce jet yield and lend those molecules into ULSD blends, and where it really impacts us is overall refinery utilization. The advantage of jet demand improving is that we can start to pull those molecules out and raise utilization along with it. I think overall we've been pleasantly surprised that the rate recovery of the jet markets from second quarter to third quarter was up 57%. So far into the fourth quarter, airline data shows a 15% to 17% increase in passenger headcount, which is encouraging. Airline nominations and load factors are also improving. Another thing you can start to see is jet tends to trade relative to ULSD; if that spreads supportive, it allows us to allocate molecules more effectively. Ultimately, increasing jet demand will support higher refinery utilization and help reduce pressure on distillate inventories.

Our next question comes from Doug Leggate with Bank of America. Please proceed with your question.

Let me just say, Joe, first of all, I for one and I think a lot of people appreciate you being as articulate and direct as you've been about the dividend question because there's too much irresponsible commentary out there. I think you're right, people need to listen to you guys. So I appreciate you making that statement. With that, I've got two quick questions. First one is on debt tolerance: can you just talk about, you've added some debt recently. You're positioned with plenty of liquidity. But what do you see as the debt tolerance? Your bonds are trading just fine it seems. If needed, what do you think about the balance sheet here?

Yes, I mean you're right. The bonds are trading well. We've got a lot of cash given the steps we've taken, and we still have our $5.7 billion of untapped liquidity which we could rely on if needed. We don't expect to need more liquidity, and I'm sure we could access other sources if necessary. We feel like we're in a pretty good spot.

Yes, I think Joe's right. We finance the business when it's attractive to do so and there's no sense in adding any degree of operational risk. I was very impressed with the rates we got; demand was very high for our offerings and we remain committed to the investment-grade ratings. There is room if we needed to do more, we don't anticipate needing to, but we certainly believe we could if necessary.

Yes, that does. Thank you. And my follow-up is more of a housekeeping issue: in your last presentation you had non-discretionary spending at around $1.5 billion. Your guidance today says a couple of billion for 2021 and sustaining capital is 60% which is obviously $1.2 billion. Is that just a low point? Is sustaining capital sustainable at that level or is something changed that has reset your sustaining capital?

Thanks Doug. This is Lane. That $1.2 billion is on the lower side. When we talk about our sustaining capital spend, we're really talking about a multi-year average over a three- or four-year cycle. That's roughly the average we feel like we need to run. We have heavy turnaround years and lighter turnaround years. So remember that a portion of the $1.5 billion is turnaround activity. It varies year to year.

Our next question comes from Paul Sankey with Sankey Research. Please proceed with your question.

Doug kind of hit on what I wanted to hit on, because the question really is the extent to which CapEx is flexible. I think you answered very well. Separately, could you talk about, give us the latest update — and I know it's a difficult question — on the election and what you think the top risks are that you face from the potential outcomes. What are the biggest concerns and do you think some concerns, for example a Democratic sweep, are overblown?

So this is Rich. If you look at it, a Democratic win directionally would likely lead to discussion of higher taxes and probably more regulation. But regardless of who wins, coming out of the pandemic the priority will be high unemployment and stimulating the economy, so the focus will be on recovery and it's hard to layer a whole bunch of new policies on top of that right away. I think you'll see a lot of campaign rhetoric that runs into the wall of reality once the new administration or Congress addresses it. Biden has a long history of supporting manufacturing and union jobs, and he has spoken positively about renewable industry support as well. So while there are policy differences, we believe many changes will be moderated by practical concerns. We're watching it carefully, but we feel pretty good about our position and don't see anything that will materially alter our ability to operate and invest.

Yes, the one thing we see Paul is there will likely be some sort of stimulus package following the election. It doesn't matter which party implements it — stimulus is likely and that would trigger greater demand for products we produce. We're watching it carefully and are well-positioned and organized to deal with whatever comes. We are not as pessimistic as many are about the potential outcomes from a change in administration.

Great, thanks. And the follow-up — there's been a lot of discussion about stimulus for airlines, etc. Can you remind us to what extent Valero has been helped out by federal government programs, if any?

I mean, we've seen substantial efforts to support the airlines and that helps reinforce demand for jet. We would benefit indirectly from support to the airline industry, but Valero itself has not been a primary recipient of airline bailout funds.

So your response implies that Valero has not received much direct government assistance? I just wanted to clarify that.

No, that's correct.

Our next question comes from the line of Roger Read with Wells Fargo. Please proceed with your question.

I guess maybe if we could go back and address a little bit the issue with the way the industry is losing money hand over fist in the current environment and that's likely to continue at least a little bit longer. What do you see — even if you don't want to name any particular company or particular unit that would be at risk — what are the kinds of things we should pay attention to from the outside that would indicate someone made the decision to shut a unit, if not absolutely permanently at least for the foreseeable future? Is it crude supply changes, demand concerns, high maintenance costs? Anything else you'd point to that signals a closure decision?

When an asset is at risk, it's usually because of a change in trade flows — product demand falling in that region combined with a lack of crude advantage. Regulatory spend is another major factor; if a refinery requires significant capital to comply with regulations and it doesn't have the margin profile to support that, that becomes a candidate for closure. Large turnaround costs or major required investments (for example a big FCC turnaround) can also push companies that have stretched balance sheets to consider shutting parts of a refinery or conversion. Location and structural competitiveness on OpEx are also key indicators. Those are the main things to watch.

I guess one last question: if you believe in the long-term success of refining, are there interesting opportunities to come along in areas you operate where you could get synergies built in, i.e., an M&A wish list? Given current stress, do you see good acquisition opportunities?

Let me start. We do believe in the long-term viability of refining. It's impractical to think we will displace liquid fuels derived from fossil fuels across the board in my lifetime. Cleaner fuels will be part of the mix and we're investing accordingly, but we believe our refining business will remain strong and successful over the long term. Regarding M&A, Rich can comment.

There's really nothing to say other than it's hard to justify any kind of acquisition right now given that we're preserving cash and we've got a queue of good organic projects that we can push. We're not buying back shares, and in this environment it's difficult to see compelling M&A activity.

Our next question comes from Paul Cheng with Scotiabank. Please proceed with your question.

Two questions. One for Jason: have you received any cash tax refund given your loss and what is your expectation — if you report a tax loss in the next 12 to 18 months — what percentage of that tax benefit would you be able to receive as a cash tax refund? The second question I can ask after Jason answers.

Paul, do you mind repeating the question real quick? It was a little tough to hear.

The first question is on the cash tax refund. Are you receiving any given the tax law and your loss carrybacks to 2015? If you are receiving a refund, what percentage of a reported tax loss in the next 12 months to 18 months would you expect to see as a cash tax refund?

We expect to get the refund in the second quarter; we expect to receive cash related to the refund.

So in other words, that would be in 2021 you would receive the refund in 2022? Any idea whether it's dollar-for-dollar or only a portion?

No, to be clear — the tax loss that we're incurring this year, we will receive the tax refund in April of next year. So that is unrelated to what our results might be in 2021.

I understand. So if you report a tax loss of say $300 million in your books for this year, do you expect to receive the full $300 million as cash or just a portion?

I'm not sure I totally understand your question, but if you look at the effective tax rate we're running, that will give you a good idea of what the refund would look like next year.

My second question is for Joe and Lane: if we look at the regulatory environment in Europe and California and governments saying they may ban the sale of internal combustion vehicles by 2035, how does that impact your outlook and game plan for facilities in those areas? Also many of your larger customers are talking about energy transition plans; do you think Valero needs to have a formal transition plan?

I'll take the first part. Trade flows and regulatory environment can drive how you think about assets. Governments' intentions and targets are often aspirational; feasibility matters. Markets and regulators often put goals out there and then adjust timing as the practicalities become clear. I don't necessarily think California, the U.K. or Europe will be zero fossil fuel overnight. With that said, regulators are pushing and we need to be mindful. We're very careful in how we think about West Coast assets and the CapEx we invest there; we manage costs and operations tightly.

On strategy, we continue to work on positioning the company for the future. We've been a leader on several fronts: early into ethanol, investing to lower carbon footprint of fuels and investing in renewable diesel. We will continue to evolve the portfolio based on market demand and use our strong refining base as a cash-flow engine to support that transition. We have targets for emissions reductions through 2025 with Board-approved projects already, so we're clearly working in this direction and not burying our heads in the sand. We'll position Valero to be successful for a long time.

Our next question comes from Ryan Todd with Simmons Energy. Please proceed with your question.

Maybe a follow-up on the renewable diesel conversations from earlier. You talked about some of the advantages, particularly the Darling partnership on the feedstock side. As you think about the expansions — the one coming in 2021 and the possible one for Port Arthur — can you talk more about positioning on feedstock logistics and transport costs? How do the relative economics look in terms of transporting product to California versus the operational cost of running a plant in Louisiana or Texas as opposed to California? How do you see competitive positioning?

Sure. We feel the Gulf Coast is the best place to be: lower capital cost to build, lower operating cost, and strong logistics. Rail infrastructure into the Gulf Coast for feedstocks is excellent and the logistics to move product out are advantaged. We don't know where the highest-priced market will be in the future — California, Canada, Europe could move — and that will shift. Our strategy is to build advantaged, low OpEx, high-flexibility plants and co-locate with a large operating refinery to reduce costs. The Gulf Coast gives us a huge logistics advantage and we intend to keep that focus.

And maybe a follow-up on the macro side for refining: third quarter differentials were a large headwind, especially for sweet and sour differentials. Is there a scenario where outlook for crude quality differentials improves meaningfully without a meaningful recovery in oil demand or absolute prices? How do you think about the next six to 12 months for differentials?

Certainly we saw very narrow crude quality differentials in the third quarter. Some of that reflected market balancing and production outages. Bringing production back online in August and recovery from storms has helped. You've seen the ASCI differential move out a bit and other differentials follow. We believe as global demand continues to improve, a greater share of incremental demand will come from OPEC and sour barrels, and you'll see a gradual recovery in many differentials as the market rebalances.

Our next question comes from Jason Gabelman with Cowen. Please proceed with your question.

I wanted to ask about the investment-grade rating and the metrics that are critical for determining that — the debt-to-cap ratio over 30% is a headline. When we're trying to assess your targets for the balance sheet, what are the right credit metrics to look at outside of net debt-to-cap? What do the agencies focus on?

This is Jason. Our investment-grade ratings are a top priority and we've discussed these matters with the rating agencies. Excellent liquidity is a key factor for them. They look through the cycle and recognize our long-term strengths: excellent refinery facilities, top operations. We don't think there's concern about our investment-grade status given those strengths. The way we structured our recent debt offering was biased toward shorter durations intentionally; we have a number of maturities in 2023 to 2027 and flexibility to manage them. The ratios the agencies look at include variations of debt-to-EBITDA, retained cash flow and net debt-to-capitalization. They placed us on negative outlook after our recent offering; that reflects a view of a delayed recovery versus earlier assumptions in April when they thought the event might be one to two quarters with stronger recovery by Q4. Now the view is more of delayed recovery and that leads to elevated credit ratios over the next 12 months. The negative outlook reflects that shorter-term view; it does not change their longer-term investment-grade view.

So they're thinking about recovery timing when assessing the rating in the 12 to 18-month horizon?

Yes, that's right. They look out the next 12 to 18 months and consider the elevated ratios and timing of recovery.

Okay, great. And a follow-up on Lane's comment on carbon sequestration, which you mentioned was one of the low carbon investment opportunities. What's the economic case — is that driven by U.S. tax credits or other markets? And on hydrogen, given refineries produce hydrogen already, any thoughts on that value chain?

When we're looking at these projects our first filter is whether they improve our carbon intensity in markets where that yields the highest value per ton. We stress test projects including the potential U.S. tax credits, such as section 45Q for sequestration, and look at LCFS and other market mechanisms. On hydrogen, we're looking at some opportunities tied to existing hydrogen plants; we can capture CO2 out of those streams to lower their intensity. We're evaluating hydrogen in that context, not necessarily as large-scale hydrogen-for-fuel-cell production at this point.

A lot of these things are being evaluated but the economics often don't work without policy support like the 45Q credit. Those tax credits are key when evaluating sequestration projects and other carbon-reduction investments.

We have reached the end of our question-and-answer session. I will now turn the floor back to Mr. Bhullar for any additional closing comments.

Great, thank you and thank you everyone for joining us. Appreciate everyone's questions. Unfortunately, we're out of time. So if you have follow-up questions feel free to reach out to the IR team. Thanks again.

Ladies and gentlemen, this does conclude today's teleconference and webcast. We thank you for your participation and you may disconnect your lines at this time.