Greetings, and welcome to Valero's third quarter 2022 earnings conference call. At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If you would like to ask a question, you may do so by pressing star one on your telephone keypad. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, 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 U.S. refineries compared to global competitors. Despite high refinery utilization rates, global product supply remains constrained due to roughly 4 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 in lieu of sour crude oils. 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 startup 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. For our other low carbon fuel opportunities, the BlackRock and Navigator carbon sequestration pipeline project is progressing on schedule and is expected to begin startup 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. 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 the 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. 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 benefit 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. 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 members' 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%-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. 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-1.78 million barrels per day. Mid-Continent at 460,000-480,000 barrels per day. West Coast at 250,000-270,000 barrels per day. North Atlantic at 440,000-460,000 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. If you would like to ask a question, please press star one on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, that's star one to register a question at this time. The first question is coming from Doug Leggate of Bank of America. Please go ahead. Oh, thanks. Good morning, everybody. Doug. Joe, I wonder if I could take the opportunity to ask just your views on a couple of big picture macro issues. I mean, the quarter, your operational performance speaks for itself. I'm obviously delighted to see the cash returns back with the buyback. 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. Any color you are comfortable sharing there would be my first comment. Then my second question, if I may, maybe it's for Lane or one of the guys. 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. 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. 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. 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 some consideration to. The team that we have involved in the process continues to work with her team. The dialogue has continued. I know that our D.C. 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. The dialogue continues, and I think they're looking for just additional opportunities that they might have to reduce the fuel price. 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. I think they realize that that would, you know, that would probably be more harmful than helpful. I think that understanding is there. 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. That's as it relates to the potential ban on exports, Doug. I mean, I do think they understand the consequences of that. I think all the general consensus is it wouldn't have the effect that they're trying to achieve. And then you wanna take the second question? Yeah, sure. Doug, this is Lane. I'll you know, from a work process, we define the mid-cycle as being, you know, sort of the average margin for the few tweaks that we think are market anomalies that go in through the entire business cycle. You know, we're not through the next business cycle yet, but we do believe structurally you've entered a period where we've had refinery closures through the pandemic. You're gonna have probably not as much investment in the fossil fuel industry, in particular refining going forward at a time when, you know, everybody's trying to understand exactly how the balances are gonna work. But our view is there'll be a higher call on refining capacity. We aren't prepared to quantify that, but we do believe the next mid-cycle will be higher than the last mid-cycle. 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. I just wonder if you could, you know, throw that into your consideration. Is that a concern for you guys in that definition of mid-cycle? I will leave it there. Thank you. You know, there has been a talk about, you know, we've seen some increases with respect to, at least on the prompt that the Chinese are picking up purchases, but I don't know that we've really seen them in the market on products that much. I'm looking at Gary, by the way. Yeah. No, I think our traders believe most of the Chinese exports are gonna stay in the region. Then, you know, even if you kinda assume some of it comes into the North Atlantic Basin, in the short term, the French refinery strikes are really set, offsetting any of that. 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. On a longer-term basis. Thanks We just have this issue where the Europeans and North America and everyone else is just sort of under ESG pressure, aren't really trying to increase refining capacity. If there is a region in the world that's gonna raise refining capacity, it'll probably be India and China. Thank you, folks. Appreciate the answers. Okay. Thank you. The next question is coming from John Royall of JP Morgan. Please go ahead. Hey, good morning, guys. Thanks for taking my question. 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 get to that bulletproof level where you can move off the low end of the 40%-50% returns, or do you think you're already there? Oh, John, that's a good question. We'll let Jason take a whack at it here. Yeah, yeah. As we've been talking about, we're still working on paying down our COVID debt. We have about $432 million left to pay off the full $4 billion after accounting for the tender offer we did in this third quarter. We're working our debt down with, l et's see, on the cash side, we're at a $4 billion cash balance. We've talked about how going forward, we like to hold more cash at $3 billion-$4 billion, probably on a base level. But if you're looking at potentially higher flat price levels or economic downturn, you maybe wanna hold a little bit more, so we bias to the upper end of that. We're close to, you know, a good spot on both of those. On a long-term debt to cap, net debt to cap, you know, we have a 20%-30% range that we target. We're at 24.5% now at the end of the third quarter, down from 40% at the highest point during COVID. We've been working it in the right direction. I'd like to be even lower. You'd like to be at the 20% range to give you even more financial flexibility going forward. That's kind of the an overview. 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. 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 diffs. Any color there, just generally would be helpful. Yeah. This is Lane. The heavy diffs are baked into our margin indicators to some degree. Those will move with it. I think, I mean, all things being equal, when you compare a third quarter to the fourth quarter, and this is really in any given year, you'll see a blending of butane benefit, you know. If you hold all the other things constant, our capture rates ought to marginally improve because we're gonna blend more butane in the fourth quarter than we did the third quarter. Obviously, if flat price moves up or down, byproducts have an offset effect. Those are all still intact. Your biggest contributions to margin capture really is gasoline and diesel. We'll just see. You know, the main thing to always keep in mind going from third quarter to fourth quarter is 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, you know, very strong through last quarter, and currently when you talk about demand surpassing 2019 levels for gasoline and diesel, is that primarily driven by strength in 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. Yeah, 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. Wholesale volumes continue to trend higher. If you look at the spot 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. Seeing really strong domestic demand through our wholesale channels of trade. Got it. Thank you. In relation to the high European natural gas prices supporting higher margins, given the recent decline in TTF and Europe's natural gas storage over 93% full in 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. I'll try. I'll take a shot at it and see if Gary can sort of see my comments. You know, we still need to reinventory the Atlantic basin with diesel, by and large. We're still. You know, when you look at inventory stocks, they're slow. You know, most of what's happening in Europe, you have all these LNG ships that are sort of floating down. You still are limited on the regasification of everything. We'll just have to see how it plays out. But certainly in the last couple of weeks, at least for our Pembroke Refinery, natural gas prices have fallen. Got it. Thank you. Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please go ahead. Good morning, everybody. Morning, Sam. We, you know, we definitely see evidence, everybody does, of this structurally higher margin environment. You know, more than just kind of through-cycle margins being higher, the market's also sort of characterized by anomalies, like a very high frequency of sort of regional blowouts or, you know, single commodity events within the stream. I was wondering if you could just maybe speak broadly to that. Not to ask too open-ended of a question, but just, is that? Are things like this a function of kind of capacity coming down globally or just a very tight market on an underlying basis? Or is it really just a coincidence where we've had, you know, kind of a bunch of one-off things happen in sequence and, you know, that might not necessarily be a go-forward trend? Yeah. I think, you know, some of it is structural. I think, you know, 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. You know, 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, you know, 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. Just to follow up on DGD and the startup 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. 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's just adjusted to that demand ahead of time. It seems like the feedstock environment has tolerated, you know, starting new capacity a little bit better than in the past. If you have any thoughts about just DGD 3 into the feedstock background, that'd be helpful. Yeah. 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. You know, thinking about, you know, some causes of that, I think some of it is, you know, 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. You know, if you look, we have not seen the increase in feedstock prices like we did last year with DGD 3 starting up. We have bought feedstock for the startup 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. Good. Thanks. Maybe one, you know, follow-up immediately on Diamond Green Diesel. You've been in pretty rapid expansion mode at DGD over the last couple of years. With the startup 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? Yeah, I think, you know, like we've talked about, you know, 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. So as you look across the industry, a lot of projects are getting deferred and delayed. You know, given the high energy prices across the world, everyone's kind of rethinking a lot of their policies. Especially in Europe, you have to step back and see, you know, are they gonna continue the path and pace that they have been on historically. I think, you know, after DGD three, we've said we will pause, reassess the market. I think SAF is becoming a lot more interesting. But overall, you know, I think there will be a pause after DGD three. Good. Thanks. Then maybe you mentioned, you know, it briefly in passing earlier, and I know it's a little speculative, but any thoughts on how you think, you know, trade routes and supply chains get impacted if Europe's ban 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 y ou know, to someplace else, South America or Africa, et cetera. Or do you think the, 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, you know, 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, you know, for some of those barrels to find homes in South America and Africa, as you mentioned. We kind of believe diplomatic pressures from the U.S. and from Europe will kind of keep a lot of that from happening, and you will see a reduction in exports from Russia. Great. 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 hear me, Joe? Yes, sir, we can. Cool. Can you talk a little bit about the strategic petroleum reserve releases? Joe, you mentioned a few things that made sour crude discounts wider, but my understanding was a lot of the drawdown in the SPR was sour 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 stop releasing the crude. Thanks. Gary? Yes. Really, you know, what we saw is with each of the SPR auctions, 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. You know, certainly early on, they were more sour barrels and we took a good volume of the SPR volume. As it transitioned 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. Are you anticipating continuing drawdowns through, let's say, 2023? Or do you think they'll have to stop eventually? 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. Yeah, thanks. I wanted to return to a topic that you had mentioned briefly earlier, which is the suggestions 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. Do you wanna talk about it first? Sure. I think. Yeah, this is Lane. I think there was two main ones, which was one was increasing or relaxing the sulfur spec on fuels. Many of the U.S. refiners didn't necessarily invest, and it looks like either making in making ultra-low-sulfur diesel as much as maybe some others or Tier three gasoline. Consequently, they're in a posture of having to export some of those, you know, some gasoline and some diesel to markets around the world that can handle the sulfur. That was really, I think, the two big ones. I mean, obviously a part of that meeting was meant to see if there was any possibility somebody could start a refinery up, and we discussed, you know, the industry discussed the difficulty in doing that. That was really the main. Yeah. Those were the main ones. I mean, yeah, waiving specs really on products. Yeah. was what we talked about. You know, the one interesting thing, Connor, that came out of it too was, you know, there was a consideration for the ability to restart refining capacity that had been shut down. I think the general sentiment was that that wasn't gonna happen. Now 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. The solution is going to probably have to come from some waiving 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, you know, 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 take just a high level effort on it, and then if we've kind of give you an idea. I mean, we're really focusing on a number of things. One is that they have clean energy tax credits in there that are enacted that are really an extension of the BTC, the blenders tax credit, which is, you know, helpful to us. There's also tax credits there for sustainable aviation fuel, and I think Eric had mentioned earlier that makes it more interesting for us to look at. Additionally, there's additions for the 45Q tax credit, which we think strongly supports carbon sequestration, and we think you're gonna see more opportunities develop around that. 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. Two questions, hopefully short. First one is for Lane. I think back in the first quarter conference call, you gave a number of $8 in the diesel crack advantage for U.S. refiner versus Europe, because of the natural gas price gap. At the time, you're using, say, if it is $25 gap. Since then, we have seen the European refiner essentially cut their natural gas consumption by half. So curious that, is there an update number you can share, and is it really that cut from $8 to $4, just linear or that we can't really do in that way? Secondly, and also that if you can give us what is your natural gas exposure by operating region for you guys. The second question is on DGD. I think that the joint venture so forward on the diesel contract as a part of the hedge operation. In a backwardation curve you had heard yet. In the third quarter, I think the backwardation curve is substantially less than second quarter. We were surprised your margin capture didn't improve, comparing yours to your benchmark indicator. Is there anything going on we should be aware that led to that or anything, any insight you can provide? Thank you. Hey, Paul. Yeah, I'll try to come back to that first question a little bit. You know, you're accurate in what I had stated in the first quarter. Today, what we're seeing, at least in our Pembroke refinery, is natural gas prices have fallen. I think what you're seeing in the Atlantic Basin in the diesel crack is, you know, the advantage is lower, but you still have a wide diesel crack, and that's because a lot of the refineries that are having to sort of re-inventory the Atlantic Basin are looking to run a lot of sweeter crude because they can't meet the fuel oil spec, right? They end up bidding up the industry, or at least the marginal guy out there is bidding up the sort of low-sulfur crude price to try to you know, to meet the demand in the Atlantic Basin. You're seeing that in discounts. You're seeing medium-sour getting cheaper. You're seeing heavy-sour getting cheaper. Part of that is also a function of redirection of all the Russian trade flow. That's really, in terms of a prompt basis, what's driving the heat crack. I don't know that Europe solved this natural gas problem. We're just gonna see. You know, there's a lot of tankers sitting offshore trying to regas. We'll just see how that goes. Eric, you want to take that? Hey, Lane, before you go on that one, I just curious that, I mean, is the advantage U.S. refiner versus Europe on the natural gas price gap, does it impact that advantage when the European refiner cut their natural gas consumption? Or that doesn't really. That's not how you should be calculate or be aware? What I'm saying is versus the fourth quarter, first quarter, really up until about three weeks ago, there was an advantage that you could see they were paying higher cost of fuel. We could also see when we use our Pembroke refinery as a proxy, we were through that, right? In other words, even though now we had eliminated all of our natural gas purchases, but what we could see was the profitability or at least your ability to. What's setting the marginal capacity out there in the Atlantic Basin is not so much around natural gas, I don't think today. I think what it is people are having to buy a very low sulfur crude oil to try to meet the low sulfur diesel spec and trying to avoid making a higher fuel oil spec. You know, in a simple term, it's a lot. Some of it's being driven by IMO 2020 and the ability some of these simple refiners can't deal with the crude oils that are available to them to restock the Atlantic Basin. I see. You actually don't think it's the natural gas is driving the advantage at all? This is just a three-week phenomenon, Paul. I'm not sure I would jump out there and try to make it an annualized thing. I'm just saying, I think most of that for the last quarter, a lot of it's just being driven by the marginal economics of a simple refiner trying to buy, you know, having to buy low sulfur crudes to meet the Atlantic Basin diesel requirements. I see. Okay. Thank you. All right, Eric, you ready? Yeah. On DGD, you know, what you said is correct, that backwardation was less severe in the third quarter than the second quarter. The margin capture issue in the third quarter was more related to the feedstock slate that we ran. You know, 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 CBOT soybean prices drop $0.05-$0.15 a pound below all of the waste oil feedstocks. When you look at that through the third quarter, that was about 80% of the impact on the margin capture. It's really related to what we're seeing is veg oils pricing at or below waste oil feedstocks. 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 DGD, 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, you know, versus what we see in waste oils. We are incrementing veg oil into DGD because we see those prices are attractive. Hey, Eric, do you have a percentage? How much is the vegetable oil you're going to run in the DGD 3? Yeah, we're not gonna give out that level of detail. What I'll say is, you know, up until the fourth quarter, we ran essentially zero veg oil. We're incrementing veg oil into the unit because of this attractive price. I see. All right, thank you. See you, Paul. Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead. Yeah. Hello, everybody. Good morning. Hi, Roger. Maybe just to come back, you know, to the cash returns to shareholders question. We're getting a lot of interest on not just the 40%-60% return, but, you know, how are you thinking about the split between those? When should we think about, you know, potential to raise the dividend? Is it as simple as, you know, you get rid of the $4 billion that came with COVID, or is there a step beyond that you wanna see? 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 know, you're earning above a typical mid-cycle. You know, kind of an expectation, I think here of greater than the mid-cycle cash returns to shareholders is pushing on us. Just curious how you're thinking about it? Yeah, this is Jason. I think Joe answered it pretty well. I ran through our cash. We're up to $4 billion now, which is getting to where we'd like to be. The debt's getting to a good level, $24.5 billion. We still like to do a little bit more. We have $430 million left just to have paid off the COVID and prefer to be at the lower end of that 20%-30% range. Yeah, we're getting into good shape, but I would say we're not declaring victory yet on. You know, Roger, Jason answered correctly. We don't know what the economic climate's gonna be like going into next year. You know, it's probably premature to certainly make a commitment right now on anything that we're going to use the balance sheet to defend. I think everyone clearly could see that we had stated in the past that we were gonna defend the dividend with the balance sheet, and we did that. and we will do that in the future. We just wanna be sure that we don't knee-jerk here and that we've got a line of sight, that we get positioned where we wanna be positioned, and then we have line of sight to the way things look going into next year before we would make that decision. I do think, you know, we've got the flywheel of the buybacks, and we talked about maybe not moving up above. By the way, it's 40%-50%, okay? You took us up to 60%. I did notice that. Okay? It's 40%-50%. We'll see. We'll use that flywheel to drive the returns. Hey, gotta try something here and there and just, you know, move the goalposts, right? All right. Well, let me try something else more on the kind of the operational side. You brought it up, as you know, 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, you know, what kind of. Would you expect to see, you know, 200,000 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, you know, as the guys have kind of gone back and looked at recessionary periods in the past, they see that product demand is kind of hit about two times GDP. Whatever kind of GDP assumption you're gonna have, you would take twice that on the impact of fuel demand. As you mentioned, more of that is gonna 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, you know, a good increase in jet demand as we would anticipate. Chinese oil demand has been down 20%. You know, at some point in time, they will come out of the pandemic and you would expect to see Chinese demand recover. The combination of both those things is that, you know, we would expect even with a typical recessionary period, you may see year-over-year global oil demand growth. All right. Thank you. Appreciate it. All right. Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead. Yeah. 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'd 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 and refining it all to run some of that high sulfur fuel oil into the cokers? Are you doing it more through WCS and so on? Yeah. This is Gary. You know, 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. You know, first, the sanctions put on Russia have caused some rebalancing. A lot of the Indian and Chinese refiners are running Urals. It's backed up Mars and heavy Canadian into the Gulf, which are driving those discounts wider. We've talked about the higher prices of natural gas around the world, caused the operating expenses running heavy and medium sour 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, you know, in the US, which has also contributed. You know, overall, I think, you know, we continue to see weakness in high-sulfur fuel oil, combined with higher refiner utilization, putting more product on the market. Some of that, you know, what we expected in IMO 2020, we're finally starting to see in the market. Lack of Chinese demand is certainly also contributing to that. You know, for us, you know, 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 that's putting more heavy Canadian on the market. We expect to see even more rebalancing occur if sanctions are ramped up in Russia. We expect this market to continue. We're certainly maximizing heavy Canadian in our system today and seeing a lot of opportunity to buy high sulfur fuel blend stocks, as you mentioned, that we're putting into our cokers. Yeah. That makes a lot of sense. 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. Just your perspective on whether as you look forward, are there bolt-on M&A opportunities? As we are seeing some indeed in the downstream markets and in low carbon markets. Or do you wanna continue to build the business on organic basis? Neil, we're very comfortable with the approach we've taken to building the business. You know, 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. We're very comfortable with the refining portfolio that we have in place today. You know, we always look at opportunities that are out there, and we'll continue to do that. The strategy that we've employed with, you know, 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're comfortable with the way we've gone about doing it, which is, you know, certainly in the Renewable Diesel business from the ground up. I think you should expect that we're not gonna jump into the market for any kind of significant transaction and we'll continue to do what we're doing. That makes a ton of sense. Thanks, Chip. 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 things. One, impacts to capture with the startup of DGD3, the ability to capture strong West Coast cracks in October. Gasoline margins were over $100 a barrel. Then any impacts from the Mississippi River drought that you saw in your footprint that could be ongoing. I have a follow-up. Thanks. You first. You wanna start with DGD3? Okay. On DGD3, margin capture I think will be challenged. One of the details of this business is when you first start up a brand new unit, you have to start up on temporary pathways that are, you know, somewhat generic to renewable diesel units. You gotta run like that for the first several months until you gather the data to get your actual carbon intensity numbers. Margin capture on DGD3 will be lower initially as we start up because you have to line out, get and like I said, get the data to then submit your actual CI numbers. I think that'll be one of the main issues as we start up DGD3. We'll certainly get volume. We'll certainly get more, you know, overall income. If you look at it whether you look at it through the margin indicator or on a dollar per gallon basis, on temporary CIs, for the first several months it will be lower. That'll line out in the back half of 2023 as we submit our data and get responses from all the different, you know, jurisdictions that you have to submit your CI numbers to. This is Lane on California. We have been executing a turnaround at our Benicia refinery, some of which, the turnaround was in the third quarter and we'll be wrapping up here in the fourth quarter. To the extent we You know, we still maximize gasoline even to the extent we could based on the operating posture we had for this turnaround. Wilmington ran at full rates. That's really, you know, you know, we'll just see how the fourth quarter wraps up with respect to the gasoline crack on the West Coast. I guess the final one around Memphis, the river levels have been impacting, you know, 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 weeks, so we expect the situation to improve. Great. Thanks. That color's all really helpful to think about 4Q. The other one just on low carbon opportunities within your portfolio. You know, 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. That's definitely something on the radar for us. As you said, carbon captured ethanol will be eligible to get into SAF, and given our footprint and our Navigator project, it will be, you know, SAF is a possibility with that ethanol product, you know, post-sequestration. That's definitely something on the radar to look at 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 & Co. Please go ahead. Hey, good morning. Thanks for squeezing me in here. I just had one question on the DGD guidance. If I heard correctly, it was still $750 million for the year, which I believe implies that Q4 volumes would be lower quarter-over-quarter despite starting up the new plant in November. Could you help us understand that? Is that just being a little conservative around the startup, or is there a turnaround at the DGD one or DGD two that we should be keeping in mind? It's a little conservative. We are in startup at DGD 3. The plan is to ramp to full rates in November. If you added that volume in, it will come in higher than the 750. You know, we're still lining the unit out and have yet to put feed into the Ecofining, so we won't know that detail until mid-November or so. From a guidance standpoint, we decided to keep the guidance at 750 till it's proven that we see that rate. Sounds good. Thank you very much. Okay. 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.