Greetings, and welcome to Valero’s Third Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. Please go ahead.

Good morning, everyone, and welcome to Valero Energy Corporation’s third quarter 2022 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 investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company’s or management’s expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we’ve described in our filings with the SEC. Now, I’ll turn the call over to Joe for opening remarks.

Thanks, Homer, and good morning, everyone. We're pleased to report strong financial results for the third quarter, credited to our safe and reliable operational performance and continued strength in refining fundamentals. Refining margins remain supported by strong product demand, low product inventories and continued energy cost advantages for US refineries compared to global competitors. Despite high refinery utilization rates, global product supply remains constrained due to roughly four million barrels per day of global refining capacity being taken permanently offline since 2020 for a variety of reasons, including unfavorable economics or as part of planned conversions to produce low carbon fuels. Product demand across our system remains strong, with gasoline and diesel demand higher than pre-pandemic levels, and jet fuel demand steadily approaching 2019 levels. Our refining utilization increased to 95% in the third quarter as we continue to maximize refining throughput. Our refining system also benefited from wider sour crude oil differentials to the Brent light sweet crude oil benchmark. The wider sour crude oil differentials are attributed to increased sour crude oil supply, the impact of the IMO 2020 regulation for lower sulfur marine fuels and high natural gas prices in Europe that incentivize European refiners to process sweet crude oils instead of sour crude oils. And we remain on track with our refining growth projects that reduce cost and improve margin capture. The Port Arthur Coker project, which is expected to increase the refinery's throughput capacity, while also improving turnaround efficiency, is expected to be completed in the first half of 2023. In our renewable diesel segment, we continue to optimize our operations, setting another sales volume record in the third quarter. The new DGD 3 renewable diesel plant, located next to our Port Arthur refinery, is currently in the start-up process and is expected to be operational in November. The completion of this 470 million gallons per year plant is expected to increase DGD's total annual capacity to approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. And for our other low-carbon fuel opportunities, the BlackRock and Navigators carbon sequestration pipeline project is progressing on schedule and is expected to begin start-up activities in late 2024. We're expecting to be the anchor shipper with eight of our ethanol plants connected to this system, which should provide a lower carbon intensity ethanol product and generate higher product margins. And we continue to evaluate other low-carbon opportunities such as sustainable aviation fuel, renewable hydrogen and additional renewable naphtha and carbon sequestration projects. On the financial side, our strong balance sheet remains a cornerstone of our capital allocation framework. In the third quarter, we reduced our debt by an additional $1.25 billion, bringing our total debt reduction to approximately $3.6 billion since incurring $4 billion of incremental debt during the height of the pandemic in 2020. And we will continue to further evaluate deleveraging opportunities going forward. Looking ahead, refining fundamentals remain strong as global product supply remains constrained due to capacity reductions and high natural gas prices in Europe, which are setting a higher floor on margins. In addition, we continue to realize the benefits from discounted sour crude oil and fuel oil feedstocks in our system. While geopolitical and macroeconomic factors may drive volatility in the market, we remain focused on what we can control, maximizing refinery utilization in a safe, reliable and environmentally responsible manner to provide essential products. We also remain committed to advancing the growth of our low carbon fuels businesses to increase profitability and further strengthen our competitive advantage. So with that, Homer, I'll hand the call back to you.

Thanks, Joe. For the third quarter of 2022, net income attributable to Valero stockholders was $2.8 billion or $7.19 per share, compared to $463 million or $1.13 per share for the third quarter of 2021. Adjusted net income attributable to Valero stockholders was $2.8 billion or $7.14 per share for the third quarter of 2022, compared to $545 million or $1.33 per share for the third quarter of 2021. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables. The refining segment reported $3.8 billion of operating income for the third quarter of 2022 compared to $835 million for the third quarter of 2021. Adjusted operating income for the third quarter of 2021 was $911 million. Refining throughput volumes in the third quarter of 2022 averaged 3 million barrels per day, which was 141,000 barrels per day higher than the third quarter of 2021. Throughput capacity utilization was 95% in the third quarter of 2022, compared to 91% in the third quarter of 2021. Refining cash operating expenses of $5.48 per barrel in the third quarter of 2022 were $0.95 per barrel higher than the third quarter of 2021, primarily attributed to higher natural gas prices. Renewable diesel segment operating income was $212 million for the third quarter of 2022, compared to $108 million for the third quarter of 2021. Renewable diesel sales volumes averaged 2.2 million gallons per day in the third quarter of 2022, which was 1.6 million gallons per day higher than the third quarter of 2021. The higher sales volumes were due to DGD 1 downtime in the third quarter of 2021, resulting from Hurricane Ida, and the impact of additional volumes from DGD 2, which started up in the fourth quarter of 2021. The ethanol segment reported $1 million of operating income for the third quarter of 2022, compared to a $44 million operating loss for the third quarter of 2021. Adjusted operating income for the third quarter of 2021 was $4 million. Ethanol production volumes averaged 3.5 million gallons per day in the third quarter of 2022. For the third quarter of 2022, G&A expenses were $214 million and net interest expense was $138 million. Depreciation and amortization expense was $632 million and income tax expense was $816 million for the third quarter of 2022. The effective tax rate was 22%. Net cash provided by operating activities was $2 billion in the third quarter of 2022. Excluding the unfavorable change in working capital of $1.5 billion, which was primarily due to our third quarter estimated tax payment and the other joint venture member share of DGD's net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $3.4 billion. With regard to investing activities, we made $602 million of capital investments in the third quarter of 2022, of which $185 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $417 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD and those related to other variable interest entities, capital investments attributable to Valero were $479 million in the third quarter of 2022. Moving to financing activities. Year-to-date, we have returned 40% of adjusted net cash provided by operating activities to our stockholders through dividends and stock buybacks, which is consistent with our guidance to be at the low end of our annual 40% to 50% target payout ratio, while focusing on deleveraging our balance sheet. With respect to our balance sheet, we completed another debt reduction transaction in the third quarter that reduced Valero's debt by $1.25 billion. As Joe noted earlier, this transaction, combined with a series of debt reduction and refinancing transactions since the second half of 2021, have collectively reduced Valero's debt by approximately $3.6 billion. We ended the quarter with $9.6 billion of total debt, $1.9 billion of finance lease obligations and $4 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was approximately 24%, down from the pandemic high of 40% at the end of March 2021, which was largely the result of the debt incurred during the height of the COVID-19 pandemic. And we ended the quarter well capitalized with $4.9 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2022 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About 60% of that amount is allocated to sustaining the business and 40% to growth. About half of the growth capital in 2022 is allocated to expanding our low carbon fuels businesses. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.73 million to 1.78 million barrels per day; Mid-Continent at 460,000 to 480,000 barrels per day; West Coast at 250,000 to 270,000 barrels per day; and North Atlantic at 440,000 to 460,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $5.10 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be approximately 750 million gallons in 2022 with the anticipated start-up of DGD 3 in November. Operating expenses in 2022 should be $0.45 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.1 million gallons per day in the fourth quarter. Operating expenses should average $0.50 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 $140 million and total depreciation and amortization expense should be approximately $640 million. For 2022, we expect G&A expenses, excluding corporate depreciation, to be approximately $870 million. That concludes our opening remarks. Before we open the call to questions, please 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. Please respect this request to ensure other callers have time to ask their questions.

Ladies and gentlemen, the floor is now open for questions. The first question is coming from Doug Leggate of Bank of America. Please go ahead.

Thanks. Good morning, everybody. Joe, I wonder if I could take the opportunity to ask just your views on a couple of big picture macro issues. I mean, in the quarter, your operational performance speaks for itself. I'm obviously delighted to see the cash returns back with the buyback. But my question, I guess, is your visit to the White House recently and your thoughts on the possibility of an export ban, product export ban that seems to be still rumbling on the table. So any color you are comfortable sharing there would be my first comment. And then my second question, if I may, maybe it's for Lane or one of the guys. But you did make a comment in your results about a higher floor on margins. I'm just wondering, I think you know our view on this, I'm wondering if you could elaborate on what you're trying to imply from that commentary? And I'll leave it there. Thank you.

No, Doug, that's great. Both good questions. So on the visit to the White House, Lane and I went in and of course, there were seven companies, I think, represented there. We ended up meeting with Secretary Granholm. And I would say that it was a constructive conversation. She was looking for things that the industry might suggest that would try to bring down the cost of fuels. And so we did, we provided her with several suggestions, which would have an effect on increasing the supply of fuel into the marketplace. Thus far, I don't believe any of those have been embraced, but at least it was put on the table for her to give it some consideration. And so the team that we have involved in the process continues to work with her team. So the dialogue has continued. I know that our DC office has spent quite a bit of time continuing to work with them. And then, of course, the supply folks back here also have been involved in those conversations. So the dialogue continues, and I think they're looking for just additional opportunities that they might have to reduce the fuel price. So Rich, is there anything you would add to that, you or Lane?

No, I don't think so. I mean, I think they understand the consequences of trying to disrupt market flows. And I think they realized that would probably be more harmful than helpful. And so I think that understanding is there. So I know they're looking at a lot of options, but I think that's the understanding they have from the industry at least.

Yeah. So that's as it relates to the potential ban on exports, Doug. I mean, I do think they understand the consequences of that. And I think the general consensus is, it wouldn't have the effect that they're trying to achieve. And then you want to take the second question?

Yes, sure. Doug, it's Lane. We define the mid-cycle as the average margin from a few adjustments we consider market anomalies that occur over the entire business cycle. We have not yet completed the next business cycle, but we believe that structurally, there have been periods where refinery closures occurred during the pandemic. There is likely to be less investment in the fossil fuel sector, particularly in refining, moving forward, while everyone is trying to figure out how the balances will play out. However, we believe there will be a greater demand for refining capacity. We are not ready to provide a specific number, but we do think the next mid-cycle will be higher than the previous one.

Guys, forgive me for the quick follow-up, but there's a lot of concern, I guess, of Chinese exports hitting the market, and obviously new capacity expansion, Lane. So I just wonder if you could throw that into your consideration. Is that a concern for you guys in that definition of mid-cycle? And I will leave it there. Thank you.

There has been some discussion about the increases in purchases by the Chinese, but I am not sure we have actually seen those products in the market to any significant extent. I'm looking at Gary, by the way.

No. I think our traders believe most of the Chinese exports are going to stay in the region. And then, even if you kind of assume some of it comes into the North Atlantic Basin, in the short term, the French refinery strikes are really offsetting any of that. And longer term, it looks like, to us, any incremental volume coming out of China will be offset by further reductions in exports from Russia as the sanctions are ramped up.

And then on a longer-term basis, just whether Europeans and North America and everyone else is sort of under ESG pressure aren't really trying to increase refining capacity. So if there is a region of the world that's going to raise refining capacity, that will probably be India and China.

Thank you, guys. Appreciate the answers.

Thank you. The next question is coming from John Royall of JPMorgan. Please go ahead.

Hey, good morning, guys. Thanks for taking my question. So you talked about bulletproofing your balance sheet in the prior quarter, and you mentioned evaluating further reductions in your prepared remarks. How much lower would you like to get on your leverage before you kind of get to that bulletproof level where you can move off the low end of the 40% to 50% returns, or do you think you're already there?

John, that's a good question. We'll let Jason take a swing at it here.

Yes, as we've discussed, we are still focused on reducing our COVID debt. We have approximately $432 million remaining to pay off the total of $4 billion, taking into account the tender offer completed in the third quarter. We are actively decreasing our debt. On the cash side, we currently maintain a cash balance of $4 billion, and we have mentioned our preference to keep a cash reserve between $3 billion and $4 billion as a baseline. However, in the event of higher price levels or an economic downturn, we may want to increase this reserve slightly, leaning towards the upper limit. We are in a good position for both debt repayment and cash reserves. Concerning our long-term net debt to capitalization, we aim for a target range of 20% to 30%. As of the end of the third quarter, we are at 24.5%, reduced from a peak of 40% during COVID. We continue to move in the right direction and aim to lower this further, ideally reaching the 20% range for greater financial flexibility. That summarizes our current status.

So we're getting close.

Yes.

To the point where, I mean, the low end of the range wouldn't necessarily be the target anymore.

Okay. That's helpful. Thank you. And then, maybe you could talk about refining captures and how they're looking so far in 4Q. I know we have, at least in October, a rising price environment, but also you're seeing some tailwinds from heavy dips. So any color there just generally would be helpful.

This is Lane. The heavy dips are somewhat reflected in our margin indicators, which will fluctuate accordingly. In comparing the third quarter to the fourth quarter, you will notice a blending benefit from butane. Holding other factors constant, our capture rates have slightly improved because we will use more butane in the fourth quarter than in the third quarter. Additionally, variations in flat prices can influence byproducts significantly. However, gasoline and diesel are the primary contributors to our margin capture. It's important to remember that the transition from the third quarter to the fourth quarter involves blending and butane.

Great. Thanks very much.

Thank you. The next question is coming from Theresa Chen of Barclays. Please, go ahead.

Good morning, everyone. I wanted to ask about your comments related to demand across your footprint first. Your wholesale volumes being very strong through last quarter, and currently, when you talk about demand surpassing 2019 levels for gasoline and diesel, is that primarily driven by strengthening your export channels? Is domestic demand in your areas of service equally strong? I'd like to get a sense of what's happening there.

Hi, Theresa, this is Gary. Really, it's the domestic markets and our wholesale volumes have trended considerably higher. We set a wholesale volume record in August. We beat that in September, and we're on pace to beat it again in October. So wholesale volumes continue to trend higher. If you look at the pump market through our wholesale channels of trade, gasoline is trending about 8% above where we were pre-pandemic levels. Diesel volumes are trending about 32% above where we were pre-pandemic levels. So seeing really strong domestic demand through our wholesale channels of trade.

Got it. Thank you. And in relation to the high European natural gas prices supporting higher margins. Given the recent decline in TTF and our natural gas storage over 93% full, lowering that Henry Hub to TTF spread. Do you see any risk for a pullback of margins as a result over the near term, while longer term, I imagine just depends on the pace of liquefaction build-out.

But I'll give it a try, and I've heard Gary mention this. We still need to restock the Atlantic Basin with diesel. Overall, inventory levels are slow. In Europe, the situation is impacted by the numerous LNG ships that are still waiting, which limits the regasification process. We'll have to wait and see how this develops. However, in the past few weeks, natural gas prices have dropped, at least for our Pembroke refinery.

Got it. Thank you.

Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please, go ahead.

Good morning, everybody.

Good morning, Sam.

We definitely observe evidence of a structurally higher margin environment, which is noticeable to everyone. Beyond just the higher margins throughout cycles, the market is also marked by anomalies, such as a high frequency of regional successes or isolated commodity events. I would like to hear your thoughts on this without asking too broadly. Are these occurrences a result of decreasing global capacity, a very tight underlying market, or merely coincidences where several unique events have happened in succession that may not indicate a continuing trend?

Yes. So I think some of it is structural. I think, as Joe alluded to in his opening, we had a lot of refinery rationalization, refining capacity converted to produce low carbon fuels. And so, much tighter supply-demand balances, which structurally means a stronger market. Some of the things you talked about on market dislocation could be more transient in nature. A lot of that is just a function of very, very low product inventories, especially in the domestic markets. I think we feel like through the winter period of time, you could see some restocking of gasoline, which could prevent some of those market dislocations from happening, at least in the short term. Diesel, on the other hand, looks to us to remain very, very tight, and I think you'll continue to see volatility in the markets due to very low inventory.

Okay. Thanks for that. And then just a follow-up on DGD and the start-up timing. You know, in the past, when you guys start up a DGD unit, we can see feedstock prices or the veg oil complex, sort of, respond. And this year, I don't know if it's a timing issue where it hasn't really started yet in earnest or if the market has just adjusted to that demand ahead of time. But it seems like the feedstock environment has tolerated new starting capacity a little bit better than in the past, if you have any thoughts about just DGD 3 into the feedstock background that would be helpful?

Yes, this is Eric. I think, what your observations are correct. We are not seeing the increase in feedstock prices like we did with DGD 2 this time last year. Thinking about some cases of that, I think, some of it is given refining margins, the conversion projects that had been announced, I think, have largely been deferred or delayed. And with the drop in LCFS prices, I think a lot of the projects have been deferred and delayed. So if you look, we just have not seen the increase in feedstock prices like we did last year with DGD 3 starting up. And we have bought feedstock for the start-up in this quarter.

Okay. Thank you so much. Have a great day.

Sam.

Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.

Thanks. Maybe one follow-up immediately on Diamond Green Diesel. You've been in a pretty rapid expansion mode at DGD over the last couple of years. With the start-up of DGD 3, will you take a pause here to kind of digest and evaluate for market conditions for a bit, or how do you think about the strategic direction of Diamond Green Diesel unit over the next five years in terms of priorities there?

Yes. I think, like we've talked about this quarter and last quarter, LCFS prices continue to drop. And I think that is taking a lot of the fun away in this space. And so as you look across the industry, a lot of projects are getting deferred and delayed. And given the high energy prices across the world, everyone is kind of rethinking a lot of their policies. So we have to, especially, in Europe you have to step back and see, are they going to continue the path and pace that they have been on historically? So I think after DGD 3, we've said, we will pause, reassess the market. I think SAF is becoming a lot more interesting. But overall, I think there will be a pause after DGD 3.

Yeah. Thanks. And then maybe you mentioned it briefly in passing earlier, and I know it's a little speculative, but any thoughts on how you think trade routes and supply chains get impacted if you expand on Russian product imports goes into effect early next year? Is there a logical home for some of that Russian product to make its way to someplace else, South America or Africa, et cetera, or do you think those Russian barrels just kind of go away and refining utilization falls dramatically there?

Our view is that you will see a reduction in Russian exports of primarily diesel. They export a little bit of naphtha, not much gasoline. But on the diesel side, you will see a reduction in exports. You do have the potential for some of those barrels to find homes in South America and Africa, as you mentioned. But we, kind of, believe diplomatic pressures from the US and from Europe will, kind of, keep a lot of that from happening, and you will see a reduction in exports from Russia.

Okay. Thank you.

Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead.

Hi, guys. Can you hear me okay?

Morning Paul.

Can you talk a little bit about the strategic petroleum reserve release? Joe, you mentioned a few things that made SPR crude discounts wider, but my understanding was a lot of the drawdown in the SPR was crude. I was just wondering how much the SPR has affected you, I guess, operationally and from a profit point of view and what your outlook is for the coming months. I would assume that you're anticipating that we taper and even start reducing the crude. Thanks.

Yes. So really, what we saw is with each of the SPR options, we have good logistics at our Gulf Coast assets to be able to receive the barrels. A lot of people really don't have the logistics in place to be able to take those barrels. So, certainly, early on, they were more sour barrels, and we took a good volume of the SPR volume as it transition to more sweeter. We still saw value in our system to take those barrels and we would expect that to continue moving forward as long as they're offering the barrels.

I know you're anticipating continuing drawdowns through, let's say, 2023, or do you think they will have to start convention?

I think you'll continue to see drawdowns at least through this year and then start to see some restocking happen next year.

Great. Thanks a lot. I'll leave it there. Thank you.

Thanks Paul.

Thank you. The next question is coming from Connor Lynagh of Morgan Stanley. Please go ahead.

Yes, thanks. I wanted to return to a topic that you mentioned briefly earlier, which is the suggestion that you made to the administration on potential pathways for reducing fuel costs. I'm curious if you could just provide a little color on the things that the industry suggested.

Well, Lane and I were both there. So, do you want to talk about it first?

Sure. This is Lane. There are two main points. One is the potential for increasing or relaxing the sulfur specifications on fuels. Many US refiners didn't invest significantly in producing ultra-low sulfur diesel or Tier 3 gasoline. As a result, they now find themselves having to export some gasoline and diesel to markets worldwide that can accommodate higher sulfur levels. So, those were the key points. Additionally, part of the discussion focused on the challenges associated with starting up a refinery, which was a significant topic of conversation in the industry.

I mean, yes, waving specs really on products was what we talked about. The one interesting thing, Connor, that came out of it, too, was there was consideration for the ability to restart refining capacity that had been shut down. And I think the general sentiment was that, that wasn't going to happen. Of course, we're not in that boat. But I mean, people had very good reasons for making the decisions that they made, and they weren't in a position to unwind those decisions. So, the solution is going to probably have to come from some waving of regulation or just reduction in demand, which we just haven't seen to-date.

Makes sense. Semi-related policy question, just given that the Inflation Reduction Act has maybe had a bit of time to be digested by the market or players out there that you talk to. What types of opportunities are you seeing as more likely or more in the money with the incentives in that bill?

This is Rich Walsh. I’ll provide a brief overview and share some insights. We are focusing on several key areas. One is the clean energy tax credits that have been enacted, which extend the Blender’s Tax Credit and are beneficial for us. There are also tax credits available for sustainable aviation fuel, which Eric highlighted earlier, making it a more appealing area for us to explore. Additionally, there have been enhancements to the 45Q tax credit, which we believe strongly supports carbon sequestration, and we anticipate seeing more opportunities for development in that area.

Okay. Got it. I’ll turn it back here. Thank you.

Thank you.

Thank you. The next question is coming from Paul Cheng of Scotiabank. Please, go ahead.

Hey, guys. Good morning.

Hi, Paul.

I have two quick questions. First, Lane, during the first quarter conference call, you mentioned an $8 diesel crack advantage for US refiners compared to Europe due to the natural gas price gap, which was estimated at $25. I've noticed that European refiners have significantly reduced their natural gas consumption. Can you share an updated figure? Also, should we expect the reduction from $8 to $4 to be linear, or is that not applicable? Secondly, could you provide details on your natural gas exposure by operating region? My second question is about DGD. I understand the joint venture is moving forward with the diesel contract as part of the hedge operation. However, I noticed that in the third quarter, the backwardation curve is considerably less than in the second quarter, yet your margin capture hasn’t improved compared to your benchmark. Is there anything we should be aware of that might explain this, or could you provide any insights? Thank you.

Hey, Paul. I'll try to address that first question now. You're correct in what I mentioned regarding the first quarter. Currently, in our Pembroke refineries, natural gas prices have decreased. However, in the Atlantic Basin, the diesel crack advantage is lower, yet there remains a wide diesel crack. This is largely due to many refineries in the Atlantic Basin needing to process sweeter crudes to meet fuel oil specifications. As a result, there's increased competition in the market, with some participants bidding up the low sulfur crude prices to satisfy the demand in the region. Consequently, you're observing discounts with medium sour and heavy sour crudes becoming cheaper. This situation is also influenced by the reallocation of Russian trade flows. In terms of immediate factors affecting the crack spread, we haven't seen Europe fully resolve its natural gas issues yet. There are numerous tankers offshore working to regasify, and we'll have to monitor how that unfolds.

Lane, before you continue, I'm curious whether the advantage US refiners have over Europe due to the natural gas price gap is affected when European refiners reduce their natural gas consumption, or if that's not relevant for the calculation.

What I'm saying is that compared to the fourth quarter and the first quarter, up until about three weeks ago, there was a noticeable advantage due to the higher fuel costs. We observed this through our Pembroke Refinery, which reflected that even though we've stopped purchasing natural gas, we could see the impact on profitability and the marginal capacity in the Atlantic Basin. It’s not just about natural gas today; it’s more about the necessity for refiners to buy very low sulfur crude oil to comply with low sulfur diesel specifications and avoid producing a higher fuel oil specification. In simpler terms, part of this situation is influenced by IMO 2020, and some straightforward refiners are struggling to handle the available crude oils to replenish the Atlantic Basin.

I see. So you actually don't think that the natural gas is driving the advantage at all?

What I'm trying to convey is that this is just a three-week situation. I'm not sure if it makes sense to consider it as an ongoing annual trend. I believe that for the last quarter, much of this has been influenced by the marginal economics of a basic refiner needing to purchase low sulfur crudes to meet the diesel requirements in the Atlantic Basin.

Okay. Thank you.

All right, Eric, you're ready?

Yes. So on DGD, what you said is correct, that backwardation was less severe in the third quarter than the second quarter. So the margin capture issue in the third quarter was more related to the feedstock slate that we ran. And as before, where we said we haven't seen an increase in feedstock prices we did see, and this is a little bit of a function of the margin indicator. We saw – see by soybean prices drop $0.05 to $0.15 a pound below all of the waste oil feedstocks. And when you look at that through the third quarter, that was about 80% of the impact on the margin capture. So it's really related to what we're seeing is veg oils pricing at or below waste oil feedstocks. And so the only thing I would say going forward to be aware of, we are increasing the amount of veg oil that we are running in the DGD complex, not because waste oils are not available, just because we see flat prices of veg oils coming down to a point where the LCFS advantages are not as strong versus what we see in waste oils. So we are implementing veg oil into DGD because we see those prices are attractive.

Eric, do you have a percentage? How much is the vegetable oil you're going to run in the DGD 3?

Yes. We're not going to give out that level of detail. What I'll say is, up until the fourth quarter, we ran essentially zero veg oil. So we're incrementing veg oil into the units because of this attractive price.

Okay. Eric, Thank you.

Thank you, Paul.

Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead.

Hey. Hello, everybody. Good morning.

Hi, Roger.

Maybe just to come back to the cash returns to shareholders question. We're getting a lot of interest on not just the 40% to 60% return, but how are you thinking about the split between those? And when should we think about potential to raise the dividend? Is it as simple as you get rid of the $4 billion that came with COVID? Or is there a step beyond that you want to see? And I think the question is growing more acute because as you look at the overall crack spread environment, right, it's one that says you're earning above a typical mid-cycle, so kind of an expectation, I think, here of greater than mid-cycle cash returns to shareholders is pushing on us. I'm just curious how you're thinking about it.

This is Jason. I think, Joe answered it pretty well. I'll ran through our cash. We were up to $4 billion now, which is getting to where we'd like to be. The debt is getting to a good level at 24.5%. We still like to do a little bit more. We have 430 left just to have paid-off the COVID and prefer to be at the lower end of that 20% to 30% range. But, yes, we're getting in a good shape, but I would say we're not declaring victory yet.

Roger, Jason provided the correct answer. We are uncertain about the economic landscape for next year, so it's likely too early to make any commitments regarding how we will utilize our balance sheet. In the past, we have stated that we intended to defend the dividend with our balance sheet, and we successfully did that. We plan to continue this approach in the future. We need to ensure that we have a clear understanding of our position before making any decisions. However, we believe we have a solid strategy for buybacks, and previously discussed maintaining our range at 40% to 50%. I noticed we briefly exceeded that at 60%, but our target remains 40% to 50%. We'll leverage that strategy to enhance our returns.

Hey, got to try something here and there, and you know that's right. All right, well, let me try something else more on the kind of the operational side. You brought it up as there is obviously a risk of a slowing economic cycle out there. What level would you think about a typical recession impact in terms of fuel demand, recognizing gasoline is already well below what we would call, kind of, a normal environment. So let's maybe think about diesel since that's the real strong part. When you think about industrial demand weakness, transportation-related weakness, right, whether it's just typical trucking, et cetera, how does that factor in? Like what, kind of, would you expect to see a couple of hundred thousand barrels go away? Is it a 10% sort of, cut top to bottom? I'm just wondering how you think about the typical magnitude impact of a recession on fuel demand.

Hey, Roger, this is Gary. I guess as the guys have, kind of, gone back and looked at recessionary period in the past, they see their product demand has hit about two times GDP. So whatever GDP assumption you're going to have, you would take twice that on the impact of fuel demand. And as you mentioned, more of that is going to be diesel, less on gasoline. I think there are some unique situations as we head into next year. One, jet demand hasn't fully recovered. And so you'll have a good increase in jet demand as we would anticipate, and then Chinese oil demand has been down 20%. At some point in time, they will come out of the pandemic, and you would expect to see Chinese demand recover. So the combination of both those things is that we would expect, even with the typical recessionary period, you may see year-over-year global oil demand growth.

All right. Thank you. Appreciate it.

Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.

Good morning team. First question is just around the high sulfur fuel oil market, and we're seeing these big heavy discounts showing up in the market. I love your perspective on, what do you think is driving it? How much of that really is the later impacts of IMO versus other dynamics in the market? And are you changing your configuration in refining at all to run some of that high sulfur fuel oil into the cokers? Are you doing it more through WCS and so forth?

Yeah. So this is Gary. As Joe touched on a few of these things, but there's a number of factors that have been really driving the heavy sour discounts. First, the sanctions put on Russia have caused some rebalancing. A lot of the Indian and Chinese refiners are running euros. It's backed up Mars and heavy Canadian into the Gulf, which are driving those discounts wider, which we talked about the higher prices of natural gas around the world caused the operating expenses running heavy and medium sours to be higher. So that causes the discounts to be wider. There's a higher naphtha content in heavy Canadian crude. Naphtha has been discounted, so that drives the discounts wider. We've seen some unplanned maintenance in the US, which has also contributed. But overall, I think we continue to see weakness in high sulfur fuel oil, combined with higher refinery utilization, putting more product on the market. So some of that, what we expected in IMO 2020, we're finally starting to see in the market. The lack of Chinese demand is certainly also contributing to that. So for us, when we look at the market going forward, seasonal maintenance in Western Canada is coming to an end. You'll see higher diluent volumes as we head into winter. So all of that's putting more heavy Canadian on the market. We expect to see even more rebalancing occur as sanctions are ramped up in Russia. And so we expect this market to continue. We're certainly maximizing heavy Canadian in our system today and seeing a lot of opportunity to buy those high sulfur fuel stocks, as you mentioned that we're putting to our cokers.

Yeah. That makes a lot of sense. And the other question is you guys have really built a wonderful business here through organically. Really haven't done much M&A in the better part of the last decade. And just your perspective on whether, as you look forward, are there bolt-on M&A opportunities as we are seeing some A&D in the downstream markets and in low carbon markets, or do you want to continue to build the business on an organic basis?

Neil, we're very comfortable with the approach we've taken to building the business. I mean, we went through the period, of course, where we grew the business. And frankly, bolted on a lot of stuff to the portfolio, which we now have largely operating to a level that we're comfortable with. And so we're very comfortable with the refining portfolio that we have in place today. We always look at opportunities that are out there, and we'll continue to do that. But the strategy that we've employed with really directing a significant part of the capital budget to the renewables businesses has made sense to us. We believe that they're very durable as is refining. But we're very comfortable with that approach, and we are comfortable with the way we've gone about doing it, which is certainly in the renewable diesel business from the ground up. So I think you should expect that we're not going to jump into the market for any kind of significant transaction. And we'll continue to do what we're doing.

Makes tone of sense. Thanks, Joe.

Thank you. The next question is coming from Jason Gabelman of Cowen. Please go ahead.

Hey, thanks for taking my questions. I have two. The first one kind of on near-term dynamics. Just thinking into 4Q, I was hoping you could discuss a couple of things. One, impacts to capture with the start-up of DGD 3, the ability to capture strong West Coast cracks in October, gasoline margins were over $100 a barrel. And then any impacts from the Mississippi River drought that you saw in your footprint that could be ongoing? And I have a follow-up. Thanks.

You want to start with DGD 3? Okay. On DGD 3, margin capture, I think, will be challenged. One of the details of this business is when you first start up a brand-new unit, we have to start up on temporary pathways that are somewhat generic to renewable diesel units. You got to run like that for the first several months until you gather the data to get your actual carbon intensity numbers. So margin capture on DGD 3 will be lower initially as we start up because you have to line out, get in, like I said, get the data to then cement your actual CI numbers. So margin capture on DGD 3 will be lower initially as we start up because you have to line out, get in, like I said, get the data to then cement your actual CI numbers. So margin capture on DGD 3 will be lower initially as we start up because you have to line out, get in, like I said, get the data to then cement your actual CI numbers. So margin capture on DGD 3 will be lower initially as we start up because you have to line out, get in, like I said, get the data to then cement your actual CI numbers. So margin capture on the DGD 3 will be lower initially as we start up because you have to line out, get in, like I said, get the data to then cement your actual CI numbers. Margin capture will be lower initially due to the temporary pathways and CIs.

This is Lane. We have been working on a turnaround at our Benicia refinery, with some of it occurring in the third quarter and concluding in the fourth quarter. We will strive to maximize gasoline production as much as possible, given the operational adjustments we made for this turnaround, and aim to operate at full capacity. We will evaluate how the fourth quarter progresses in relation to the gasoline crack on the West Coast.

I guess, the final one around Memphis, the river levels have been impacting us at our Memphis refinery, both the ability to clear the refinery and supply the river terminals. As of this morning, both northbound and southbound traffic out on the river is wide open, expected to be there for the next couple of weeks and we expect the situation to improve.

Great. Thanks. That colors are really helpful to think about 4Q. And then the other one just on low carbon opportunities within your portfolio. In addition to the DGD venture, you also have an ethanol business, and it seems like with the carbon capture project that you're installing there and the Inflation Reduction Act, maybe ethanol to jet is a technology that makes sense, particularly given weaker ethanol margins. Is that something that you're looking at either to complement any SAF growth you would pursue within DGD or as an alternative investment instead of pursuing SAF near-term within DGD? Thanks.

Yeah. So that's definitely something on the radar for us. As you said, ethanol carbon, carbon captured ethanol will be eligible to get into SAF. And given our footprint and our Navigator project, it will be in – SAF is a possibility with that ethanol product post-sequestration. So it's definitely sort of a somebody on the radar to look at sort of post-2025 when Navigator comes online.

Thanks.

Thank you. Ladies and gentlemen, we're showing time for a final question. The final question today is coming from Matthew Blair of Tudor, Pickering Holt. Please go ahead.

Hey, good morning. Thanks for squeezing me in here. I just had one question on the DGD guidance. If I heard it correctly, it was still $750 million for the year, which I believe implies that Q4 volumes to be lower quarter-over-quarter despite starting up a new plant in November. Could you help us understand that? Is that just being a little conservative around the start-up, or is there a turnaround at the DGD 1 or DGD 2 that we should be keeping in mind?

It's a little conservative. We are in start of the DGD 3. The plan is to ramp to full rates in November. So if you added that volume in, it will come in higher than the $750 million. But we're still lining the unit out and have yet to put feed into the Echo finer. So we won't know that detail until mid-November or so. So from a guidance standpoint, we decided to keep the guidance at $750 million. It's proven that we see that rate.

That sounds good. Thank you very much.

Thank you. At this time, I'd like to turn the floor back over for closing comments.

Great. Thank you, Donna. We appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any additional questions. Thank you, everyone, and have a great week.

Ladies and gentlemen, thank you for your participation. This concludes today's event. You may disconnect your lines at this time, and enjoy the rest of your day.