Greetings, welcome to the Valero's fourth quarter 2022 earnings conference call. At this time, all participants are on a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations. Thank you, Mr. Bhullar. You may begin. Good morning, everyone, and welcome to Valero Energy Corporation's 4th 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 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 finished the year strong with our refineries operating at 97% capacity utilization in a favorable refining margin environment. In fact, this is the highest refinery utilization for our refining system since 2018. I'm also proud to share that 2022 was the best year ever for combined employee and contractor safety, which is a testament to our long-standing commitment to safe, reliable, and environmentally responsible operations. As we saw during most of 2022, refining margins were supported by low product inventories, which resulted from the significant permanent global refinery shutdowns and the continued recovery in product demand. Our refining system also benefited from heavily discounted sour crude oils and fuel oils. These discounts were driven by increased sour crude oil supply, high freight rates, and the impact from the IMO 2020 regulation for lower sulfur marine fuels. High natural gas prices in Europe incentivized European refiners to process sweet crude oils in lieu of sour crude oils, adding further pressure on sour crude oils. Our refining projects that are focused on reducing cost and improving margin capture remain on track. The Port Arthur Coker project is expected to be completed in the second quarter of 2023 and will increase the refinery's throughput capacity and ability to process incremental volumes of sour crude oils and residual feedstocks while also improving turnaround efficiency. In our renewable diesel segment, we continue to expand operations, we set another sales volume record in the fourth quarter with the successful commissioning and startup of the new DGD Port Arthur Renewable Diesel Plant in November. That project was completed under budget and ahead of schedule and brings DGD's annual production capacity to approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. In the ethanol segment, BlackRock and Navigator's carbon sequestration project is still progressing on schedule and is expected to begin startup activities in late 2024. We expect to be the anchor shipper with 8 of our ethanol plants connected to this system, which is expected to result in the production of a lower carbon intensity ethanol product that should significantly improve the margin profile and competitive positioning of the business. We continue to advance other low carbon opportunities, such as Sustainable Aviation Fuel, Renewable Hydrogen, and additional renewable naphtha and carbon sequestration projects. Our gated process helps ensure these projects meet our minimum return threshold. On the financial side, we continue to strengthen our balance sheet, paying off all of the incremental debt incurred during the COVID-19 and ending the year with a net debt to capitalization ratio of 21%. Looking ahead, we expect low product inventories and continued increase in product demand to support margins, particularly for U.S. coastal refiners that have crude oil supply and natural gas advantages relative to global refiners. We continue to see large discounts for heavy sour crude oils and fuel oils that we can process in our system. The startup of the Port Arthur Coker is also expected to have a significant earnings contribution in the back half of 2023, supported by wide sour crude oil differentials and strong diesel margins. In closing, we're encouraged by the refining outlook, which, coupled with the contribution from our strategic growth projects in refining and renewable fuels, should continue to strengthen our long-term competitive advantage and shareholder returns. With that, Homer, I'll hand the call back to you. Thanks, Joe. For the fourth quarter of 2022, net income attributable to Valero stockholders was $3.1 billion or $8.15 per share, compared to $1 billion or $2.46 per share for the fourth quarter of 2021. Fourth quarter 2022 adjusted net income attributable to Valero stockholders was $3.2 billion or $8.45 per share, compared to $988 million or $2.41 per share for the fourth quarter of 2021. For 2022, net income attributable to Valero stockholders was $11.5 billion or $29.04 per share, compared to $930 million or $2.27 per share in 2021. 2022 adjusted net income attributable to Valero stockholders was $11.6 billion or $29.16 per share, compared to $1.2 billion or $2.81 per share in 2021. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables. The refining segment reported $4.3 billion of operating income for the fourth quarter of 2022, compared to $1.3 billion for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $4.4 billion compared to $1.1 billion for the fourth quarter of 2021. Refining throughput volumes in the fourth quarter of 2022 averaged 3 million barrels per day. Throughput capacity utilization was 97% in the fourth quarter of 2022. Refining cash operating expenses of $5 per barrel in the fourth quarter of 2022 were $0.14 per barrel higher than the fourth quarter of 2021, primarily attributed to higher natural gas prices. Renewable diesel segment operating income was $261 million for the fourth quarter of 2022 compared to $150 million for the fourth quarter of 2021. Renewable diesel sales volumes averaged 2.4 million gallons per day in the fourth quarter of 2022, which was 851,000 gallons per day higher than the fourth quarter of 2021. The higher sales volumes were due to the impact of additional volumes from the DGD's St. Charles plant expansion and the fourth quarter of 2022 startup of the DGD Port Arthur plant. The ethanol segment reported $7 million of operating income for the fourth quarter of 2022 compared to $474 million for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $69 million compared to $475 million for the fourth quarter of 2021. Ethanol production volumes averaged 4.1 million gallons per day in the fourth quarter of 2022. The higher operating income in the fourth quarter of 2021 was primarily attributed to multiyear high ethanol prices due to strong demand and low inventories. For the fourth quarter of 2022, G&A expenses were $282 million, and net interest expense was $137 million. G&A expenses were $934 million in 2022. Depreciation and amortization expense was $633 million, and income tax expense was $1 billion for the fourth quarter of 2022. The annual effective tax rate was 22% for 2022. Net cash provided by operating activities was $4.1 billion in the fourth quarter of 2022, and $12.6 billion for the full year. Excluding the unfavorable change in working capital of $9 million in the fourth quarter and $1.6 billion in 2022, and the other joint venture member's 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 $4 billion for the fourth quarter and $13.8 billion for the full year. Regarding investing activities, we made $640 million of capital investments in the fourth quarter of 2022, of which $349 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $291 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 $538 million in the fourth quarter of 2022 and $2.3 billion for the year, which is higher than our annual guidance, primarily due to project spend timing on the Port Arthur Coker project and the accelerated completion of the DGD Port Arthur plant. Moving to financing activities, we returned $2.2 billion to our stockholders in the fourth quarter of 2022 and $6.1 billion in the year, resulting in a 2022 payout ratio of 45% of adjusted net cash provided by operating activities through dividends and stock buybacks. With respect to our balance sheet, we completed additional debt reduction transactions in the fourth quarter that reduced Valero's debt by $442 million through opportunistic open market repurchases. As Joe noted earlier, this reduction, combined with a series of debt reduction and refinancing transactions since the second half of 2021, have collectively reduced Valero's debt by over $4 billion. We ended the year with $9.2 billion of total debt, $2.4 billion of finance lease obligations, and $4.9 billion of cash and cash equivalents. The debt to capitalization ratio, net of cash and cash equivalents, was approximately 21%, 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 year well-capitalized with $5.4 billion of available liquidity excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and $500 million to growth. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.59 million barrels per day-1.64 million barrels per day. Mid-Continent at 415,000-435,000 barrels per day. West Coast at 245,000-265,000 barrels per day. North Atlantic at 415,000-435,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $4.95 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2023. Operating expenses in 2023 should be $0.49 per gallon, which includes $0.19 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4 million gallons per day in the first quarter. Operating expenses should average $0.51 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $130 million. Total depreciation and amortization expense should be approximately $655 million. For 2023, we expect G&A expenses, excluding corporate depreciation, to be approximately $925 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. Thank you. 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. The first question is coming from Theresa Chen of Barclays. Please go ahead. Good morning, everyone. Thank you for taking my questions. My first question is related to your macro outlook over the near term. With respect to Russia, how do you see the EU embargo or price cap on Russian products and imports playing out specifically to the diesel as well as VGO situation? Theresa, this is Gary. I think, you know, initially we felt like even with the ramp-up in sanctions, you would just see a rebalancing of trade flows, much like we saw with crude and resids. Most people in the trade today think that the sanctions will actually result in a reduction in Russian refinery utilization, and you'll see lower exports of VGO and diesel coming out of Russia when the sanctions take place. Got it. Clearly, there's been a focus on an elevated amount of maintenance in the first half of this year, plus some unplanned downtime. How big of an impact do you think this will be on near-term refining economics? How real do you think this is? What are the implications on your own refining earnings, taking into account that you have your own maintenance program to work through as well? I'll probably have that. Yeah. The market is very, very tight. You know, we're looking at total light product inventories 55 million barrels below, you know, the five-year average. Typically this is a period of time where you see restocking take place. With the winter storm outage and high maintenance activity, you know, we just haven't been able to restock inventories, which, you know, sets the year up very nicely in terms of refinery margin perspective. Theresa, this is Lane. You know, as we've been pretty consistent, we don't do a lot of commentary around our turnaround activities. Nonetheless, I mean, the first quarter and third quarter is our heavy turnaround periods when we have turnarounds. You know, that's sort of, seasonally, that's how we execute our maintenance. Thank you. Thank you. The next question is coming from Doug Leggate of Bank of America. Please go ahead. Good morning, everyone. Thanks for taking my questions. Happy New Year, guys, for those I haven't spoken to yet. Thanks, Doug. Joe, I don't know who you want to direct this to, but I'm curious about the Coker economics. When you laid out the original plan to bring this online, we were in a very different diesel resid market than we are today. Could you know, as you see the Earnings power of that facility, you know, as it stands, maybe, you know, at strip or however you wanna characterize it. Can you give us an idea of what your expectations are relative to what it looked like when you first set out the project? I've got a follow-up question. Yeah. Doug, we'll let Lane take a crack at this one. Yeah. Hey, Doug. I hope you're doing all right. It's just to remind everybody, our FID, I think, was $325 million. That's sort of based on mid-cycle. We sort of look back at it in sort of 2018, I think the EBITDA was around $420. If you use sort of fourth quarter, you know, it's, you know, it's on the order of probably $700 million, maybe a little bit more, dollars. If you use those kind of margins. Obviously, it's, I don't know if we have incredible foresight, but it's great to be lucky. Better to be lucky than good. Exactly right. Yeah. It'll have a, you know, assuming all this holds, and I think our outlook, at least for this year is that these sort of resid prices and distillate cracks will hold. It'll be a. The timing's pretty perfect. Just to be clear, Lane, I know you don't wanna be specific on timing, but when would you anticipate this up by the end of the second quarter, or how are you thinking about startup? I'm going to be fairly specific 'cause we're right here. We're gonna be mechanically complete somewhere late Feb, early March. We expect oil in somewhere, you know, late April or early May. Thank you. Joe, I hate to do this, but I got to ask the cash return question. Your balance sheet, you've managed it, or Jason maybe, back to below COVID levels. Your dividend still hasn't moved, and your share count is now down, I guess, about 7%. All things considered, it seems you've got a lot of capacity for, dividend, you know, to restart dividend growth. How can you walk us through what you're thinking on cash returns? Thanks. Doug, that's a very fair question, and we'll let Jason share his strategy around this. Yeah. I'll give a little context too 'cause this quarter we did meet a goal which will kinda change how we look at things. Back prior to the pandemic, we were frequently at the high end or even above our target return payout range of 40%-50%. During the pandemic, we were very committed to our dividend, paying the dividend alone put us way above our 40%-50% target range. As you know, during COVID, we had to take on another $4 billion of debt in 2020. One of our main objectives as the financial situations improved post-COVID was to pay back this incremental debt, which we've been aggressively working on. We've messaged that while we're working on this competing goal of deleveraging, we would stay at the lower end of our 40%-50% payout range, which is what we've been doing. In the fourth quarter, we were able to repurchase $442 million of debt, which is the final step in us meeting our goal of deleveraging by $4 billion. With that in sight, during the quarter, we increased our stock purchases to $1.8 billion, and we're able to end the year at a 45% payout ratio. We're able to work our way back to the midpoint of our target range for the full year. Now that we've paid off our pandemic debt and built our cash balance up to a good level, you should reasonably expect us to be looking at mid-level or higher payout targets given the construction margin environment as we move forward. Now on the dividend side- That's very clear. Go on. Go on. Please go ahead, Jason. Okay. Yeah. You'd asked about dividend too, which is the other piece. Yeah ... of the puzzle. We continue to aim for a dividend that's sustainable and competitive versus our peers. We would also like to show growth. As you know, the dividends, we hadn't had any growth since the first quarter of 2020. 'Cause first of all, we had the pandemic, which we had to work our way through, and then we were rebuilding cash and working our debt down. Now, as I've said, we've kind of met those goals, so we would like to return to a pattern of growth as we move forward. I appreciate the full answer, Jason. As you know, Joe, we like to see cash on the balance sheet. Thanks so much for that. All the best, folks. Thank you. Yeah. Net zero debt, Doug. Take care, buddy. Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead. Yeah, good morning. I guess I'd like to jump in here on just call it crude structure in the market, right? We had big SPR releases a lot of last year. Those seem to have at least, I don't know if I'd say ceased, they've definitely eased quite a bit. You mentioned the Russian sanctions coming up. That's really more of a product thing. Then we've had the Venezuelan barrels start to enter the Gulf of Mexico. I guess as a broad question, how are you looking at crude availability and crude diffs as we, you know, get into the early days of 23 here? Yeah. This is Gary. I think, you know, our outlook on crude quality differentials is we expect the market to stay fairly consistent. You know, the key drivers really on the quality differentials have been more sour crude on the market, refineries running at high utilization rates, which produce more high sulfur fuel oil. With the IMO 2020 regulation, it's decreased the demand for high sulfur fuel oil. All those factors come into play, you know, affecting the supply-demand balances around high sulfur fuel, and then high sulfur fuel really drives the quality discount. We don't see much changing, at least in the near term, in terms of where those quality differentials are. As a follow-up on that, I think, Joe, you mentioned, you know, with the Russian ban, we might see less VGO on the market. Maybe, Gary, those were your comments. If there's less VGO in the Atlantic Basin in general, what is your expectation for a substitute feedstock into the summer, the secondary units and the, and the, you know, kind of follow-on impacts on distillate production? You know, I mean, hey, Roger. This is Lane. I'll take a shot at it. Yeah. I think what you'll see, we were concerned about it going into this past year, was VGO availability. We sort of squeaked through with some of the way some of the refineries in the Middle East started up. You know, I think some people stockpile VGO. I mean, the answer to that is it'll remain tight. Ultimately, what it affects is gasoline production. You know, if you believe distillate cracks are gonna hang in there where they are, you'll have clear margins by VGO into a hydrocracker. It'll challenge FCC's economics through the summer if in fact, we, it gets tight. Great. I'll. That's my 2, so I'll leave it there. Thank you. Thanks, Roger. Thank you. The next question is coming from John Royall of J.P. Morgan. Please go ahead. Hey, guys. Good morning. Thanks for taking my question. was hoping for your view on China reopening and how that could trickle through the market, particularly when you think about the new refining capacity coming on and they appear to still be releasing big batches of export quotas. Anything on China reopening would be helpful. Thanks. Yeah. This is Gary. I think, you know, we've certainly seen the Chinese more active in the market, both purchasing feedstocks and in the product markets as well. You know, it looks to us like a lot of the product exports from China are staying in the region, although we occasionally see some exports making their way into our market. Our view is that you'll see significant demand recovery in China by the second quarter, a lot of that ramp up in refinery utilization in China will be needed to, you know, supply the domestic demand. On the new refinery capacity, you know, at least our supply-demand balances still show year-over-year demand will outpace capacity additions, we're not too concerned about it. You know, a lot of that capacity really doesn't make a lot of transportation fuels. You know, some of the big refineries in China, it's less than 50% total gasoline, jet, and diesel yield. A lot more petrochemicals and fuel production. Great. Thank you. That's helpful. On the renewable diesel side, can you talk about how the feedstock market is absorbing DGD 3 and, assuming this is the case, why it's been kind of easier than having pushed up advantage feedstock the way it did with DGD 2? Yeah, this is Gary. We haven't really seen a big change in feedstock costs with DGD 3 coming on. As you said, we did see a big change where waste oil feeds really equilibrated to soybean oil with DGD 2 in 2021. With the startup of DGD 3, we've seen prices hold pretty flat. We saw that soybean oil actually, at least CBOT's soybean oil quote, came pretty flat to waste oils in October and November. We saw the soybean oil quote drop really with the EPA announcement on their RFS obligations for the next 3 years. Overall, to answer your question, we haven't seen a big change in feedstock prices. It's been pretty stable. Thank you. Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please go ahead. Good morning. Thank you. Hey, Sam. In the prepared remarks you mentioned, you know, European energy costs driving optimization opportunities in the U.S. v ia a lot of different factors. Energy costs in Europe have crashed and, you know, diesel cracks are still rising and those optimization opportunities are still there. Can you talk a little bit about maybe what's going on in Europe from your perspective that's kind of sustaining these advantages, even though the gas cost side is maybe out of the equation? I'll start, if Gary wants to sort of add his lane, by the way, Sam. You know, natural gas still at, I mean, at the U.K. and really in the Netherlands is still nominally around $20 per million BTU. Comparing that today, you know, sort of the Houston Hub, I mean, Henry Hub is probably at nominally $3 and change. There's still a significant difference between natural gas costs now. With that said, you know, we'll use our Pembroke Refinery as a proxy. You know, natural gas really hasn't driven our signals in over a year. I guess what I'm saying, now we don't have an SMR and we don't have a big hydrocracker, so we don't have a lot of insight into how that, you know, flows through to their marginal economics on those units. You know, what I'm saying is high natural gas prices in Europe, you know, at least for us, hasn't changed our signals, which is max run max at our Pembroke Refinery. Okay. That's really helpful. I guess just as a follow on, it's a little bit related, but it's back to Port Arthur. I mean, the coker is starting up at this high run rate, and you've got a new renewable diesel facility there that's very cost advantage, if for no other reason than just its integration with the refinery. This is a facility that's probably the most valuable fuels complex in the world at this point, I would say. I don't even know what the question is, to be honest with you, but I'm just trying to get at the facility level contribution to the system. We like where you're going, Sam. Yeah. I mean, You know, if it's dragging up the entire Gulf Coast system with it, because of optimization, opportunities that it comes with. I mean, just sort of, I guess a plant level contribution would be helpful. What was that last question? Contribution at the plant level. We can't really say that. You know, we do appreciate your comments around it. I mean, if you think about what this coker does, at least, you know, we'll heavy the refinery up and, our intermediate purchases, or if you think about our VGO comments, will be down, you know, significantly. It better integrates, you know, sort of vertically integrates that refinery and makes it way less, sort of. As you said, it's a very important asset. It makes us way less, I'd say significantly less-Dependent on intermediates to fill out the refinery. Obviously the renewable diesel plant there is gonna be very helpful. Mm-hmm. You're right, Sam, it's a very valuable complex to us. All right. Well, thanks so much. Have a great day. You too. Thank you. The next question is coming from Paul Cheng of Scotiabank. Please go ahead. Hey, guys. Good morning. Good morning. Good morning. Can I go back into Port Arthur? Mainly with the Coker coming on stream. We understand that, I mean, one of the decisions behind it that it will allow you during the turnaround, you can still run the facility. During the long turnaround period, how that impact Port Arthur in terms of the crude slate, overall throughput and product yield? Are you talking about the turnaround portion of it? Or are you just talking about... No, outside the turn. I mean, we understand the turnaround. Now you have two cokers, so you can- I sort of alluded to it a little bit. continue running the plant and you don't have to shut it down. I'm more interested if it is not during the turnaround, how the new coker addition will really impact in terms of your crude oil slate, your product yield, and your overall throughput. As I said to Sam, it's, we'll heavy up considerably. You know, today we run some light crudes and medium crudes. You'll see us run significantly more heavy. It may be plus rate probably over time, you know, by looking back at the FID some, but it's not as much as you would think. In terms of distillate, that's really the net product we make out of this, and it's a sort of a +15 to +25, depending on the crude diet in terms of distillate. What it really is a reduction in feedstock purchases for us. In addition to, like we said, is the turnaround efficiency. Right. We assume that is a 55,000 barrel per day, you will see an incremental run of heavy and mediums to the tune of 150,000 barrel per day? I'm sorry, Paul, can you repeat that? The coker, the capacity is 55,000 barrels per day. Right. Should we assume you will heavy it up by about 150,000 barrels per day of the heavy and medium sour crude? No, we're not increasing crudes by 150,000 barrel per day. We're heavying up. You'll see our rates, I don't know, normally go from. I don't know, it's public here. I gotta be careful. You know, am I okay to advance the cause here? It's sort of a. You know, we run anywhere from 340-360 today, 375, depending on the crude diet. I think we could potentially go up +30 to +40 on crude, depending on how heavy we are or light we are. it, that's sort of what happens. it just changes. When we do this all the time, whenever we change our crude diet, it'll. We sort of have to spot in intermediate purchases to finish our conversion units out. You know, what'll happen is we'll reduce the amount of intermediate purchases depending by significantly on the base, and tuning the refinery between how heavy we are and how, you know, we'll change, you know, sort of, you know, sort of the how our crude run rates. It's not a plus 150. No. I No. I'm saying not the overall throughput increase by 150. I'm saying that will you increase the run of a heavy and medium sour crude, by 150,000 barrel per day with this coker? Will it increase? We would have to get back to you. It's gonna be a lot. I mean, I would have to go back and see how much heavy we incremented on in terms of the volume. I will have to get back with you. You can get back with Homer, assuming we disclose that. I don't know. Okay. The I don't know, I don't know whether we want to disclose that. Second question is that in your North Atlantic, the margin in this quarter is really, really strong, even compared to the benchmark indicator. Can you maybe just help us better understand that, what may be some driver outside just the market condition, if there's any? Hey, Paul, which margin are Valero's overall one or the? North Atlantic. North Atlantic. Your North Atlantic. All right. Well, I didn't really. It's not that much stronger versus the prior quarter. I mean. That's right. It's just, the way we look at it is fairly flat. Your North Atlantic. Yeah. Your North Atlantic, you said, I think, $29. No, but I'm saying when versus prior, it's like 7-9- Capture was only up a margin. Yeah. Capture rate was up just a little bit. Okay. We will take it off line with Homer. Thank you. Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead. Good. Thanks. Maybe a follow-up on some things that you maybe touched on a little bit earlier in the call. I think from the macro point of view, at some of the, you know, what appear to be at least whether they're structural or lingering improvements in kind of underlying profitability for the business. It seems like the global system is exceptionally tight in terms of generating low sulfur product, maybe that's a post IMO effect. Is that a fair statement? Have you seen kind of a post IMO, have you seen a structural change or tightness in the ability of the global refining system to generate ultra-low sulfur product? Is that something that sticks with us for a long time and, you know, on the margin drives higher distillate margins? Yes, I think so. You can see that. You know, a couple places you can really see it, the low to high spread on fuel oil, you can certainly see the gap that's occurred, and then just general weakness in high sulfur fuel. I think it tells you that the industry really is tight on capacity to upgrade high sulfur fuel into low sulfur products. We've really seen that, you know, starting early last year, and it's continuing and we don't see anything that changes that. Right. Thanks. Then maybe just one on the renewable diesel side. I mean, RVO guidance for the 2023 to 2025 timeframe didn't appear very supportive for renewable diesel on its surface. Any thoughts on what your takeaways were overall, whether you see the market as potentially oversupplied this year, and whether this may result in pushing more marginal players out of the market? Obviously, you have a structural cost advantage, so you're on the low end of the curve. Do you expect I guess how, you know, how did you read the guidance? What do you think the impact will be over the next, you know, year or two on the market? One thing that we saw with the RFS obligation is that they kept the ethanol target at 15 billion gallons, which means you're still gonna be in a situation at some point in the year where you have to use the D4 RIN to cover the D6 obligation because the ethanol blending won't reach 15 billion gallons. That mechanism is still in there. To your point, the future obligations were higher, but not as high as people expected. When you saw that announcement come out, you did see a big drop in soybean oil prices, as well as a lot of pressure on or question on whether or not all these soybean crush facilities were gonna get built based on that lower obligation going forward. You know, it's a little bit of a mixed bag that, you know, there's still gonna be a short on the D6 RIN, there is definitely a lower growth curve on the D4 RIN, you know, in this current proposal. We'll have to see how that plays out. There's still a lot of talk about a lot of the policy trying to move away from soybean oil as a feedstock, both in Europe and in the U.S., at least in terms of conversations. You know, everyone's trying to figure out is that part of what's at play with this lower RFS proposal. Overall, as you said, you know, we're a waste oils unit that isn't affected by that. As you said, we will be competitive, regardless of the obligation, compared to our peers. We'll just have to see how this plays out. I don't know, Rich Lashway, if you had other comments about sort of the future outlook on the RFS proposal. I know there's gonna be a lot of problems in the industry. Yeah, I mean, the one thing I would hit on is this the elements of the eRIN that they put in it. That's probably the thing that we find, you know, most problematic with the rule. EPA is trying to convert the RFS into a, you know, a subsidy for EVs, for autos. Obviously, we'll be commenting very heavy on that. We feel that the RFS is really set out by Congress, and the intent was for it to be used to promote liquid renewable fuels like the use of soybean and corn and for ethanol. We don't think trying to convert this into some kind of a usurper for EV purposes really is consistent with the underlying obligations and intent of Congress with the RFS. Great. Thank you. Thank you. The next question is coming from Connor Lynagh of Morgan Stanley. Please go ahead. Yeah, thanks. I kind of wanted to continue that line of questioning there. I appreciate this is a little bit ridiculous since you just brought DGD 3 online. What is this sort of, you know, policy vision make you think about DGD 4 or some of the opportunities that you'll have when you have your carbon capture system online for your ethanol plants? Just where is your head on where future renewables growth for you guys might be? Well, you know, previously we said we would take a pause after DGD 3 and kind of reassess the market. We're still lining out DGD 3. It's, you know, project went great. It came in under budget. It was 9 months ahead of schedule. It's met design. It's met its design rates already. I'll just say that, you know, the project team, the operations team, and the fuel compliance team did a great job making this a very smooth startup, and we're not having any problem moving sales out of DGD 3 into markets. As I said before, we haven't seen an increase in feedstock prices, everything looks very competitive with DGD 3 coming up. That all being said, you know, I think, we continue to do the engineering on the SAF project, for the DGD platform, and then we continue to support the Navigator pipeline for the CO₂ sequestration for our ethanol plants. All of that still says that there's a lot of opportunity with our platform, given its location and competitive position. What's your thinking around exploring potential Alcohol-to-Jet or other avenues to approach the SAF market? Yeah. I think there's two things. Obviously, what's key to that is the sequestration project has to go first. In order for ethanol to qualify for SAF, you have to get below the 50% GHG targets for the EU. If you assume that pipeline is done in the next couple of years, it will qualify our ethanol platform into SAF. The other thing that we've learned is With these SAF projects, you still have to blend that with conventional jet to make the final SAF product. If you think about our platform, we have the ethanol, we have the carbon sequestration, and we've got the conventional jet on the refining side, it does look like, you know, we would have a lot of advantage in just a complete supply chain into a finished SAF product. That all looks like it's something we will continue to look at, as we get closer to reality on this carbon sequestration pipeline. All right. Thanks very much. Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead. Good morning, team, and congrats on a great quarter. The first question was around jet cracks. We're seeing that premium relative to diesel really blow out some markets. Would love your perspective on: do you think there's a structural premium in jet? How do you see those premiums playing out over time? Yes. I think in the short term, you know, a lot of what you're seeing, the premiums on jet are primarily in New York Harbor and the Florida market. It's still a bit of an overhang from the winter storm outages that we had in the US Gulf Coast, causing those markets to be exceptionally tight. It looks to us like probably mid-month in February, you'll get some resupply, you know, which will help jet supply in those regions. Overall, you know, we expect jet demand to increase significantly this year, you know, overall, a lot of tightness in the distillate markets. That's helpful. Then just a follow-up is around just the demand levels. I mean, we've historically anchored to EIA on some of the U.S. demand levels, and the numbers are noisy. I mean, I think the last four-week trailing number was down 11%, which is hard to reconcile with the fact that disty is 20% below the five-year from an inventory perspective and gasoline below the five-year as well. Just would love to hear what you're seeing through your own wholesale system in terms of demand, and any thoughts on real-time color there. Yeah. We, we share the view. The DOE numbers look low to us, and we would expect them to be corrected going forward. Our wholesale numbers are trending pretty high. Gasoline volumes through our wholesale channel are about 12% above where they were pre-pandemic levels, which we don't necessarily think is representative of the broader markets either. For us, I think the number we focus on are more around the mobility data, which is kind of showing vehicle miles traveled flat to slightly above where it was pre-pandemic levels, with some improvements in the efficiency of the fleet. You know, it would say gasoline demand down maybe in the 2% range is what we kind of believe is most likely. Yeah, that makes more sense. Thanks, guys. Thank you. The next question is coming from Jason Gabelman of Cowen. Please go ahead. Morning. Hey, Jason. I got a couple of questions. First, I want to ask about the US Gulf Coast intermediate imports, the resids. I understand some of that's gonna be backed out with the Port Arthur Coker project, but you'll probably be taking some in still. You know, as these resid differentials have widened throughout the year, I imagine it's been a pretty large benefit to your capture rates in 2022. I was hoping you could help frame that and if you expect resids to the discount to stay wide in 2023 and continue to contribute to stronger captures, despite your commentary that you expect some of the Russian VGO to be taken off the market. I have a follow-up. Thanks. Hey. This is Lane. I'll start on that. I mean, I think we, you know, we'll probably We always look at heavy crude versus fuel oil. I mean, one of the things that's happened sort of post-Russia. You know, we used to be big buyers of M-100 out of Russia, and obviously we don't buy that anymore. We've canvassed the world and figured out alternative sort of fuel oil feedstocks, and they're plentiful, largely based on what Gary has mentioned. I mean, you have a lot of incremental crude going into low complexity, and they're struggling making sulfur. You can see that in a 3.5 weight% discount to virtually everything else. We do believe that's gonna continue, I think, through this year. As Valero, you'll see us buy more heavy crude post-Coker, and you'll see us buy some more fuel oil, and less intermediates. Yeah. The only thing I would add is, you know, for the full year 2022, resid probably didn't have a significantly positive impact on our capture rates just because after the Russian sanctions and those barrels came off the market for really the second, third quarter, you know, it was rebalancing the trade flows. In the fourth quarter, we certainly saw a significant impact. Got it. Thanks. My follow-up is on DGD. Given the startup of DGD 3, I suspect there was a larger distribution to the joint venture partners. I was wondering if you're willing to disclose what that distribution was. Now that you're gonna likely moving forward, have more access to the cash from DGD in the form of ongoing distributions, does that impact how you think about the payout ratio at all? Thanks. Well, maybe I'll start on. Yeah. On the DGD side. you know, it just started up. We haven't even got to the conversation of cash distributions yet. The expectation is, this year it should be, With capital spending coming to a close with the project that there should be more cash spinning off from the joint venture. I don't know, Jason, if you have comments on this. Yeah. No, that's right, Homer Bhullar. I mean, having DGD 3 finished, we'll have excess cash. You know, they're always looking at new capital projects, so maybe they'll find another way to deploy it. Otherwise, there should be cash coming out. We do include that in our calculus when we're looking at payout ratios. I guess that's all I had on it. Got it. Thanks. Thank you. The next question is coming from I'm sorry, Matthew Blair of TPH. Please go ahead. Hey. Thanks for taking my question. Good morning, everyone. Do you have any Good morning. thoughts on the Q1 2023 refining capture rate? Seems like we might wanna be just a little conservative here. I think your refining guidance implies like 86%-89% utilization, so, you know, probably a heavier turnaround period. Some other factors like butane blending and octane spreads. You know, still good, but looks like they're coming down from Q4 levels. I guess directionally, does that make sense that we'd wanna be more, more conservative on capture in Q1 and anything else we should consider there? Yeah, I don't know that you need to be more conservative on capture rates. Obviously, we have seasonal maintenance. We'd have to look at the material balances to figure out how that actually impacts the, sort of the dollars per barrel capture rates. I wouldn't jump to conclusion it changes appreciably from Q4 to Q1. Both quarters you're blending butane. Both quarters you have fairly wide sour discounts. We'll just have to see how that plays out. Obviously, we have some maintenance or turnarounds are occurring in Q1. I mean, that's normal for us. When we do turnarounds, this is the heavy quarter for us versus the rest of the year. Got it. Then, for DGD, how should we think about the feedstock mix going forward? You know, your old guidance was one-third fats, one-third corn oil, one-third UCO. You started up DGD 3 and your partners acquired some more tallow, production. It, it seems like we might wanna inch up maybe a little bit on the fats compared to that one-third guidance, maybe inch down on the UCO. Is that fair? Do you have anything more specific on that? Well, you know, I guess we don't normally get into that level of detail on feeds. What I would say is, you know, the whole, you know, DGD platform is built for waste oils, it's always gonna favor, you know, the UCOs and tallows and inedible corn oil over other feeds from a CI standpoint. You know, how each of those individual feedstocks play is always, that's very dynamic. You know, the thing I'd say is what we do see, maybe just to add some color, is we are running a lot more of international feedstocks, both coming from Darling as well as just more broadly in the world. Those are waste oils. We, you know, we ran some veg oil in the fourth quarter, because, you know, as we spoke earlier, the prices of it became attractive. Going forward, I think it's always gonna be some mix of those 3 waste oils as the most attractive feeds. Great. Thank you. Thank you. We're showing no additional questions in queue at this time. I'd like to turn the floor back over to Mr. Bhullar for closing comments. Thanks, Donna. I appreciate everyone joining us today. Obviously, if you have any additional questions, please feel free to reach out to the IR team. Thanks, everyone, and have a great week. Ladies and gentlemen, thank you for your participation. This does conclude today's event. You may disconnect your lines or log off the webcast at this time. 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