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spk16: Greetings and welcome to the Bolero Energy Corp third quarter 2023 earnings 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 Bollar, Vice President, Investor Relations and Finance, Thank you. Please go ahead.
spk13: Good morning, everyone, and welcome to Valero Energy Corporation's third quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President, Jason Frazier, our Executive Vice President and CFO, Gary Simmons, our Executive Vice President and COO, 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 InvestorVolero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial 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 earnings release and filings of the SEC. Now I'll turn the call over to Lane for opening remarks.
spk14: Thank you, Homer, and good morning, everyone. We are pleased to report strong financial results for the third quarter. In fact, we set a record for third quarter earnings per share. Funding margins were supported by strong product demand against the backdrop of low product inventories, which remained at five-year lows despite high refinery utilization rates globally. The strength in demand was evident in our U.S. wholesale system, which matched the second quarter record of over one million barrels per day of sales volume. Our refineries operated well and achieved 95 percent throughput capacity utilization in the third quarter. which is a testament to our team's continued focus on operational excellence. We continue to prioritize strategic projects that enhance the earnings capability of our business and expand our long-term competitive advantage. The DGD Sustainable Aviation Fuel, or SAF, project at Port Arthur remains on schedule and is expected to be complete in 2025. Once complete, we expect the Port Arthur plant to have the optionality to upgrade up to 50% of its current 470 million gallon annual renewable diesel production capacity at SAF. The project is estimated to cost $315 million, with half of that attributable to Bolero. With the completion of this project, Diamond Green Diesel is expected to become one of the largest manufacturers of SAF in the world. On the financial side, we honored our commitment to shareholder returns with a payout ratio of 68% of adjusted net cash provided by operating activities through dividends and share repurchases in the third quarter. And we ended the third quarter with a net debt to capitalization ratio of 17%. In closing, while there are broader factors that may drive volatility in the market, we remain focused on things we can control. This includes operating our assets efficiently in a safe, reliable, and environmentally responsible manner, maintaining capital discipline by adhering to a minimum return threshold for growth projects, and honoring our commitment to shareholder returns. With that, Homer, I'll hand the call back to you.
spk13: Thanks, Lane. For the third quarter of 2023, net income attributable to Valero stockholders was $2.6 billion or $7.49 per share compared to $2.8 billion or $7.19 per share for the third quarter of 2022. Adjusted net income attributable to Valero stockholders was $2.8 billion or $7.14 per share for the third quarter of 2022. The refining segment reported $3.4 billion of operating income for the third quarter of 2023 compared to $3.8 billion for the third quarter of 2022. Refining throughput volumes in the third quarter of 2023 averaged 3 million barrels per day, implying a throughput capacity utilization of 95%. Refining cash operating expenses were $4.91 per barrel in the third quarter of 2023, higher than guidance of $4.70 per barrel, primarily attributed to higher than expected energy prices. Renewable diesel segment operating income was $123 million for the third quarter of 2023 compared to $212 million for the third quarter of 2022. Renewable diesel sales volumes averaged 3 million gallons per day in the third quarter of 2023, which was 761,000 gallons per day higher than the third quarter of 2022. The higher sales volumes in the third quarter of 2023 were due to the impact of additional volumes from the DGD Port Arthur plant, which started up in the fourth quarter of 2022. Operating income was lower than the third quarter of 2022, primarily due to lower renewable diesel margin in the third quarter of 2023. The ethanol segment reported $197 million of operating income for the third quarter of 2023, compared to 1 million for the third quarter of 2022. Ethanol production volumes averaged 4.3 million gallons per day in the third quarter of 2023, which was 831,000 gallons per day higher than the third quarter of 2022. Operating income was higher than the third quarter of 2022, primarily as a result of higher production volumes and lower corn prices in the third quarter of 2023. For the third quarter of 2023, G&A expenses were $250 million, and net interest expense was $149 million. Depreciation and amortization expense was $682 million, and income tax expense was $813 million for the third quarter of 2023. The effective tax rate was 23%. Net cash provided by operating activities was $3.3 billion in the third quarter of 2023. Included in this amount was a $33 million favorable change in working capital and $82 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $3.2 billion in the third quarter of 2023. Regarding investing activities, we made $394 million of capital investments in the third quarter of 2023, of which $303 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $91 million was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD, Capital investments attributable to Valero were 352 million in the third quarter of 2023. Moving to financing activities, we returned 2.2 billion to our stockholders in the third quarter of 2023, of which 360 million was paid as dividends and 1.8 billion was for the purchase of approximately 13 million shares of common stock resulting in a payout ratio of 68% of adjusted net cash provided by operating activities. This results in a year-to-date payout ratio of 58% as of September 30, 2023. With respect to our balance sheet, we ended the quarter with $9.2 billion of total debt, $2.3 billion of finance lease obligations, and $5.8 billion of cash and cash equivalents. Debt to capitalization ratio net of cash and cash equivalents was 17% as of September 30, 2023. And we ended the quarter well capitalized with $5.4 billion of available liquidity excluding cash. Separately, as reported by Navigator last week, they canceled their CO2 pipeline project. We still see carbon capture and storage as a strategic opportunity to reduce the carbon intensity of conventional ethanol, which would also qualify it as a feedstock for sustainable aviation fuel. Without carbon capture and storage, conventional ethanol does not have a pathway into SAF under today's policies. We continue to evaluate other projects to sequester CO2. Turning to guidance, we still 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 the balance to growth. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.77 to 1.82 million barrels per day, Mid-Continent at 445 to 465,000 barrels per day, West Coast at 245 to 265,000 barrels per day, and North Atlantic at 470 to 490,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.60 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 49 cents per gallon, which includes 19 cents per gallon for non-cash costs, such as depreciation and amortization. Our ethanol segment is expected to produce 4.4 million gallons per day in the fourth quarter. Operating expenses should average $0.39 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 $145 million, and total depreciation and amortization expense should be approximately $690 million. For 2023, we expect G&A expenses 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 to ensure other callers have time to ask their questions.
spk16: 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 the handset before pressing the star keys. Again, that's star one to register a question at this time. Today's first question is coming from Teresa Chen of Barclays. Please go ahead.
spk01: Good morning and thank you for taking my questions. I first like to ask about your outlook for near-term refining margins and specifically on the gasoline side. We've seen significant volatility recently, especially early in October. What do you think explains the recent downside and how does that compare with demand across your footprint? Maybe going back to Lane's earlier comments on your wholesale system and just generally, how do you think gasoline margins trend going forward?
spk07: Good morning, Theresa. This is Gary. Yeah, I think, you know, you had several factors that contributed to the sharp sell-off in gasoline. You kind of had the market view that hurricane season was over. You were approaching RVP transition. And then the DOE put out some fairly pessimistic demand numbers. And so all that kind of hit at once and caused a fairly significant sell-off in gasoline. In terms of the outlook, you know, going forward, we would expect gasoline to kind of follow typical seasonal patterns, weaker cracks, kind of the fourth quarter and first quarter. The thing we're really looking at is, you know, the fundamental that looks good to us is the market structure still doesn't really support storing summer grade gasoline, you know, putting gasoline in New York Harbor for driving season next year. So as long as that's the case, you know, our view would be then when you get to driving season next year, demand picks back up, you'll see cracks respond.
spk01: Thank you. And on the crude oil side, in terms of light-heavy differentials, given the heightened geopolitical risks in the Middle East and coupled with the incremental then-soiling production following the recent sanctions relief and taking also into account the potential near-term startup of Dos Bocas, how do you think about the impact of all these variables on light-heavy differentials, and how do you see this evolving from here?
spk07: Yes, you know, really the key driver on the light heavy differentials continues to be the 4.5 million barrels a day that OPEC Plus has off the market. So, you know, we saw fairly tight differentials in the third quarter. They have moved wider despite the geopolitical issues that you've discussed. You know, some of that is just typical seasonal patterns. You've had less high sulfur fuel burn for power generation in the Middle East, so high sulfur fuel discounts have widened some. We've seen some turnaround activity, especially in Pad 2, that pushed some heavy sour back on the market, causing differentials to widen out. Freight markets actually have a fairly significant impact on those differentials as well. So freight moving higher is causing the differentials to move. But we kind of see, until the OPEC Plus comes back on the market, that you'll have narrower heavy sour differentials, and they'll follow typical seasonal patterns.
spk16: Thank you, Gary. Thank you. The next question is coming from Sam Margolin of Wolf Research. Please go ahead.
spk18: Hey, everyone. Thanks for taking the question. This might be one question but in two parts, which I know you guys love. So it goes back to the gasoline comment, and it just seems like the market might be more seasonal than it had been in the past just because of, you know, the way consumers kind of travel and work. And then but at the same time, you know your system has gotten a little more diesel oriented with the Port Arthur coker and you know Valero has a history of Really strong sort of capture results and execution results in the fourth quarter when there's typically a lot of volatility and dislocations Around all these markets. So the question is you know it do you think that this kind of enhanced seasonality and gasoline is something we should get used to in future years and and In terms of your configuration and position within that, is it arguably better than it was before you brought on some recent projects?
spk07: Thank you. On the first part of the question, in terms of even more seasonality around gasoline, I can't say that we're really seeing that. We did see sales throughout our wholesale system fall off a little bit after Labor Day. But they've actually recovered quite nicely. And we're back into that million barrels a day of sales. Gasoline sales year over year are up 2% in the current market from where they were last year at this time. Diesel sales are up a little stronger at 8%. So I don't think it really is a seasonability factor that's impacting gasoline, at least in the domestic markets.
spk14: So as Blaine on the left said in the second part, Sam, We really had a view, since I'm going to say the early 20-teens, where we saw that diesel would be sort of the fuel of the future. It's the economic driver. So not only did we do the Coker that you alluded to here recently, we also built the two big hydrocrackers. We revamped the two big hydrocrackers. This was all in an effort to make our system more robust in its ability to move around and specifically be able to move towards making more and more deflate out of our assets.
spk18: All right. Sounds good. Thank you so much.
spk16: Thank you. The next question is coming from Doug Leggett of Thanks America. Please go ahead.
spk17: Thanks, guys. Lane, thanks for having me on. I've got a couple of questions, if I may. I guess the first one is, I guess, about the Port Arthur coker and more generally what you're seeing going on in the Gulf Coast as it relates to heavy or advantaged sour crude spreads. And I guess my point is Das Bocas obviously looms large in Horizon, but Maya seems to have behaved very differently from your indicator from WCS. And I realize that's largely your benchmark. So I'm just curious, are we seeing the capture rate from the cocker that you anticipated? And what's your prognosis, I guess, for those advantage crude spreads that are obviously a big factor in that project?
spk14: I'm going to hand this off to Gary and Greg. I think, Gary, you might answer the heavy sour part, and then Greg is going to answer this capture rate around the coker.
spk07: Yeah, so we've seen heavy sour discounts widen back out. In Canada, they're back on apportionment on the pipelines. It looks like forecasts for fairly robust production in Canada. You're seeing the Venezuelan back on the market. And then our view is even when the focus does start up, You know, it may take some mile off the market, but probably increases fuel yield for Mexico. And so that COCR, you know, we can use that as a feedstock as well. And I'll let Greg address the capture question.
spk02: Yeah, and Doug, you know, what I'd say about the COCR is it operated very well for the quarter, certainly consistent with our expectations. And so the project's generating good, strong economic value, both by lowering feedstocks, some of the things Gary's talking about, and also enabling us to increase throughput.
spk17: Sorry, guys, on Das Bocas, is that impacting spreads on the Gulf Coast materially?
spk07: I don't think there's any impact today.
spk17: Okay, thanks. My follow-up's a quick one. Maybe it's for Jason, but another $1.8 billion of buybacks. You've now bought back, I think, about 15% of your shares in the last year and a half. You've still got plenty of cash on the balance sheet, and we know this sector is notoriously seasonal. I'm just curious how we think about your deployment or strategy of buybacks into seasonal periods when you perhaps get more opportunistic.
spk08: Thanks, Doug. If it's okay, I'll talk about our approach to buybacks is driven by our thoughts around cash, the dividend, and debt. I'll walk you through that and how we're thinking about the rest of the year, and then we can see if there's more you want beyond that. So on cash, as you said, we ended the quarter at 5.8 billion. We've indicated minimum target of four, so we're very comfortable with us being in that current range now. On the debt side, we always proactively look at our portfolio through a liability management lens on an ongoing basis, but we certainly don't have any needs to pay down any debt at this time. Net debt to caps, as of September 30th, is 17%, so it's been under our target range, so we're in good shape there. And on the dividend, We aim to maintain a dividend that's competitive, growing, and sustainable through the cycle. And we feel like we're in a reasonable range now. I wouldn't want to get into more specifics on timing or potential dividend increases at this time. And then that brings us to buybacks. And you know our approach to buybacks is to have the annual target of 40% to 50% of adjusted net cash from operations. And we view the buybacks as the flywheel supplementing our dividend to hit whatever our target is for the year. In the third quarter, we had a 68% payout. Year to date through the third quarter, we're at 58%. So I would say under these conditions, even given the softer seasonality in the fourth quarter, you should definitely expect us to pay out over 50% for the year. And you may recall, prior to the pandemic, that was a fairly regular practice. The five years before the pandemic, I think we averaged like a 57% payout. So in these periods where we have greatly above average, free cash generation, that will probably continue to be our practice.
spk17: The clarification, Len, if you don't mind, the fact you're already above 50%, the high end of your payout, does that preclude stepping into additional buybacks for the balance of this year?
spk08: No, no, it doesn't. We look at it on an annual basis, and I would think we'll be over 50 for the year. So it definitely doesn't preclude buybacks.
spk17: Thank you. Thanks so much.
spk16: Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.
spk09: Good, thanks. Could you talk a little bit about what you're seeing in renewable diesel markets? 3Q margins were obviously quite soft. Indicators have been weak. Was there any impact from hedging losses in the third quarter, and maybe could you help um if there were you know kind of rough estimate of maybe what that was and then can you just more broadly talk about what you're seeing and in terms of supply demand in the marketplace you know impact of uh rim pricing and rbo limitations etc sure ryan this is eric i think you know we saw the rin prices drop pretty quickly kind of in that september and and into october
spk19: And really, as you stare at that drop, it was kind of on the news that there was the anticipation of a couple big startups at the end of the year that have now been delayed. It was also on the news that there was going to be, with Russia freezing out its exports, that it would force the U.S. to export more, therefore drop the obligation. So the combination of all that news kind of caused a precipitous drop in the RINs kind of right at the right at the end of the quarter and into the beginning of the fourth quarter. The real margin loss there is really because, you know, fat prices have since adjusted in the spot market, but obviously there's a lag of our fat prices that kind of carried on that, you know, have since started to catch up with this drop in credit prices. But, you know, we'll see that, you know, continue to carry through through the fourth quarter. But overall, I think that's really what we're seeing. You know, the spot margin is cleaned back up. VAT prices continue to come off. You know, you really see all of that being kind of a return to profitability here in the fourth quarter. So, you know, that's really what we see going on in the RD market. Okay. Thank you.
spk09: um and then maybe in switching on the refining side as we think about pad five um you all said it was really quite strong um through third quarter on a relative basis across the country uh and into the early parts of the fourth quarter um can you talk maybe about what you're seeing overall in terms of kind of supply demand in in pad five across your operations there There's a lot of moving pieces with some refineries that are, you know, that have transitioned off the market from conversions coming right now. So how do you, as you look forward over the next few, do you expect that market to stay relatively tight for the foreseeable future? And how do you think about relative to your operations there?
spk07: Yeah, Ryan, this is Gary. I think, you know, our view of Pad 5 is that, you know, with the renewable diesel coming into the market, the market should be well supplied on the distillate side. but it's going to be very tight on gasoline. You just don't have the gasoline production that you used to have with the refinery conversions. And so when one refinery goes down, it's going to create a lot of shortness in the market.
spk09: Thank you.
spk16: Thank you. The next question is coming from Manav Gupta of UBS. Please go ahead.
spk12: Guys, you are known for your capital discipline and You look at a lot of projects and in the end, very few actually make it through the funnel. We are somewhere in October. You guys haven't talked about a major project yet. And I'm just wondering if 2024 would then be more of a quick hit projects. I mean, Coker has already come online. So when I look at 2024, should we think of as a year where you could be doing more quick hit projects versus a mega project, which generally can go on for three to four years?
spk14: Hey, Manav, this is Lane. So the way I would say it, I agree with you, but we still believe we'll spend somewhere between half a billion to a billion dollars a year of strategic capital. But when you look at sort of what's the nature of those, certainly in the refining side, they are going to be shorter cash cycle types of projects. Instead of a big, like a coker type project, there'll be a series of small projects. And then when you further drill down, what do we look for? We look for refining projects that lower our cost to produce. We also like projects that improve our reliability. And then, of course, we like the whole renewable line in terms of its ability for us to drop the carbon intensity of our fuels. And as you also said, we're very careful about our communication on projects. We like to be a little closer to FID or at FID before we really talk about them.
spk12: Perfect. Just a quick follow-up. We have seen some sanction relief on the Venezuelan side. You were buying from Chevron even before that. And Chevron had been giving the indications that they could ramp up over there. So can you help us understand what kind of incremental volumes could come to the market from the Venezuelan side in probably next two or three years?
spk07: Yeah, this is Gary. So if you look, there's about 250,000 barrels a day of exports from Venezuela. Most of that volume is going to the Far East. But with the lifting of sanctions, it has the potential to make its way to the U.S. Gulf Coast.
spk12: Thank you.
spk16: Thank you. The next question is coming from John Royal of JPMorgan. Please go ahead.
spk10: Hi, good morning. Thanks for taking my question. So we've talked about coastal light heavy diffs and how they've tightened up pretty significantly. Can you remind us how much flexibility you have in your system to run lights versus heavies versus mediums?
spk02: Hey, John, this is Greg. So we can flex quite a bit. What you'll tend to see us do is when the medium grades look attractive, we'll ramp that up and kind of back down to both the lights and the heavies. Conversely, when heavy sours get more attractive relative to the medium grades, we'll ramp up the heavies. I don't remember the exact percentages. We can get those to you. I think they might actually be in our deck. Yeah, it's there. But that tends to be what drives us to kind of swing between those different grades.
spk10: Great. And then maybe you can talk about the bead and utilizations in 3Q. You didn't call out anything in particular, but, you know, you're above the high end in I think every region but one. It seems like the system ran quite well. Are there any moving pieces to call out? Maybe, you know, maintenance getting pushed out or anything of that sort? Or is it just better than expected operations?
spk14: You know, I would say we didn't, you know, the third quarter is always going to be a period where you don't have a lot of turnaround activity. I mean, some of it might leak over from the second or you might start a little bit of going into the fourth. But, you know, each system, you know, industry-wide, we're not unique in that sense. Most of your turnaround work is either done in the first and second or the fourth quarters. And so it should be a high utilization. And obviously, we've emphasized reliability, gosh, for the last, I don't know, more than a decade. We have the programs that we have. So you would expect us when we're not having turnarounds that have a pretty high level of utilization of our assets.
spk10: Thank you.
spk16: Thank you. The next question is coming from Joe Latch of Morgan Stanley. Please go ahead.
spk05: Hey, good morning, all. Thanks for taking my questions today. So I wanted to start on the diesel side. So you talked about gasoline cracks, but I don't think we've hit on diesel much, which has remained really strong here. So I was just curious what your thoughts are The setup for diesel here into the winter, we have low inventories in both the U.S. and Europe, and last year we kind of had a similar level of tightness and were bailed out by a warmer winter. So just curious on your thoughts on the setup for diesel margins.
spk07: Yeah, so diesel demand remains very strong. You know, I guess I mentioned diesel sales in our system are up about 8% year over year. Our view of the broader markets is that diesel demand in the U.S. is probably down about 1% year-to-date from where it was last year, and that's mainly due to the warmer winter we had last year. Our guys estimate we lost about 125,000 barrels a day of diesel demand due to the warmer weather. So inventories remain below the five-year average level. Demand remains good. So you're heading into winter with low inventories, and we would expect strong diesel cracks through the winter. and could get very strong if we have a colder winter. Awesome.
spk05: Thank you. And then shifting gears a little bit, so we've talked a little bit about our D margins being pressured here, so I was just hoping you could touch on some of the regional dynamics that you're seeing and economics of selling into other states on the West Coast or potentially Canada to offset maybe the lower LCFS prices that we've seen in California.
spk19: Yeah, we absolutely see. California has become kind of the floor of the RD market. We see more opportunity in Oregon, Washington, and Canada as kind of the growth opportunities. And so we absolutely look to maximize our product sales into those markets. California continues to talk about raising the obligation for 2030. They've sort of pushed off a lot of their – they're still doing a lot of their conferences and workshops on that. We still fully expect that at some point they are going to announce the changes to be effective sometime next year, and that will increase the LCFS price in California. But in the meantime, we continue to look at – again, you kind of mentioned that. We still have the advantages being on the Gulf Coast. You have access to all the global feedstocks. You have access to all the global markets. So it gives us a lot of capability to go to different markets. And we continue to see waste oils advantaged versus vegetable oils from a CI standpoint. So you look at that low-cost producer on the Gulf Coast, that just continues to be kind of the winning formula for being able to have flexibility to go to different markets in the RD space.
spk05: Awesome. Thanks for taking my questions this morning.
spk16: Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.
spk06: Good morning. Elaine, first question is for you. It's been a couple months since you stepped into the job as CEO. We love your perspective on early observations, recognizing the strategy has been very consistent and steady for a long time, and you've been a big part of it. but early observations as the new leader of the organization and key strategic priorities that we haven't really talked about here on the call thus far.
spk14: Sure hasn't been a couple of years, Neil. I'm just going to say that. No, it's been great. You always got to remember I was an integral part of really Joe's team really from the beginning of his CEO tenure, and as you've mentioned, it's been a very successful one. You know, are there things that I'm trying to do maybe a little bit differently? I'd say I put my thumb on the scales on certain issues maybe a little bit, and I maybe unweight others. But largely speaking, our strategy is the same because it was successful, and it's currently successful. I don't know that, you know, I have any real plans to deviate from that. Obviously, the world can change, and we would respond accordingly. But, you know, the world looks, you know, at least this business looks a whole life like it did a year ago. So, and our outlook is pretty much unchanged.
spk06: Now, we definitely appreciate the consistency. The second question, it's a smaller part of your business, but it's always you can create volatility in earnings is ethanol. I'm just curious on your outlook for that business and how far away are we from mid-cycle as you think about it?
spk19: Yeah, the ethanol obviously has had a good year this year. with lower corn prices and low natural gas prices. So the ethanol margins have been, I would say, higher than what we would call a mid-cycle. But it's not really exceptionally higher than mid-cycle. It's actually been fairly strong. But I would say, looking back historically, ethanol is always kind of a steady drumbeat business. We do see that the biggest opportunity here is still this low-carbon opportunity and some of the growth in other markets in the world. Again, you know, we are 30 percent of the export capability of ethanol for the U.S., and so we see this interest in the world lowering its carbon footprint by increasing its ethanol blending. So Canada has become an E10 country almost overnight. There's talk about that going to E15 next year. We're seeing other countries that are starting to look at incremental ethanol blending. And then there's a lot of interest in ethanol as a feedstock into chemicals and solvents and paints. And so I think we still see a lot of good opportunities for ethanol globally that I think will keep us in a very strong margin environment. And then, obviously, I mean, so much of that depends on weather, ultimately. I mean, obviously, no one can control that. But, you know, the U.S. is a big ag country. We have a lot of capability to grow a lot of corn. And so as long as, you know, that holds up, then I think ethanol's got a good outlook.
spk06: Thanks. Great, Collin.
spk16: Thank you. The next question is coming from Paul Chang of Scotiabank. Please go ahead.
spk15: Hey, guys. Good morning. Two, hopefully, quick questions. First, maybe either it's for Ling or Gary. It looks like the Ed Thien and Napa branding economic right now is really good with the winter grain. If we're looking at your system, what is the incremental percentage of the Gasoline supply will increase as a result of those branding for you versus, let's call it, third quarter, the level, or that fourth quarter last year, whatever the comparison you want to use. And secondly, I want to see if you can give us any color that how's the turnaround cycle look like for you next year, and whether that, compared to this year, going to be about the same lighter, heavier, also, and also that whether you think the industry is going to have a normal cycle next year after the catch-up this year or that the catch-up is going to continue into next year. Thank you.
spk07: So, if I understand correctly, the first was how much really does the gasoline pool swell as you go to higher RVP gasoline? Is that what you were asking, Paul?
spk15: Yeah. I mean, that every year that when we go to the winter grade, obviously, you see more branding, but that with the economic look like it's actually very attractive for the branding. And I assume that given the wind degree, it will also allow you to have more flexibility if you want to brand the straight leather into the system. And it looks like it's very economic also.
spk02: Yeah, Paul, this is Greg. So you're right. You definitely increase the amount of primarily butane that you blend into the gasoline. It ranges depending on which region you're in and the change in specs. It's in the 5% to 10% range. And then you're right that to the extent that butane has a higher octane than the pool, it does allow you to put more of the lower octane components into the blend, naphtha being one of those right now that looks pretty attractive. Yeah, sorry.
spk15: Please, go ahead.
spk14: I think it was your second question around turnarounds. We sort of had a policy for a while that we don't give any real outlook on our turnaround or the industry's turnaround behavior.
spk15: I can just go back into the earlier question about Greg's answer. Any kind of, say, because when it is more economic, you tend to brand more, but on the other hand, gasoline crack is not great right now. So I'm trying to understand that, how the two years going to impacting in your thinking or your action here.
spk14: I think, so if I understand you, Paul, Back to winter blending, obviously nap is cheap. Butane is relatively cheap. And we always look at economic signals to try to determine how much gasoline we're producing. And that compares to, for the reformulated grade, they might require less butane. And then there's specs that you hit. I mean, you would think you would get near 10% butane in the pool, but a lot of times we hit other specifications in the finished gasoline besides RVP. And so, I mean, that's fair. Yeah, that's fair.
spk12: Yeah.
spk15: Very good. Thank you.
spk16: Thank you. The next question is coming from Jason Gableman of TD Cowan. Please go ahead.
spk00: Morning. Thanks for taking my questions. I wanted to first go back to uses of cash or returns of cash. I should say, and I know Valero has the 40% to 50% payout ratio. It seems like you're returning a majority of the excess cash post-dividends via buyback, maybe two-thirds of that excess cash. Is that kind of how we should think about return of cash moving forward? Essentially, all of the excess cash or a majority of it, beyond what you pay out in the dividend is going to be going towards the buyback for the foreseeable future. And I think some color around that could help the market bring some of that potential future buyback value forward. And I have a follow-up. Thanks.
spk14: Hi, Jason. This is Lane. So, directionally, you're correct. But we still have to – some of our cash obviously goes to sustaining our asset. So, that's something that we're committed to because we want to make sure that we're A, that we have the earnings potential or assets stay in a posture that we can always generate the right earnings with the market conditions. And second, we maintain the dividend. And then we do believe we still have this sort of half a billion to a billion dollars of strategic capital. To the extent all that's done, all the excess cash will go to buybacks.
spk00: All right. Great. Thanks. And my second one is kind of on the strategic growth outlook. You know, we've seen... some of your larger peers use equity to buy up companies recently. And if I think about some of the potential areas you could expand into, like chems, like low carbon fuels, those valuations have come down relative to where Valero trades. And I know Valero doesn't typically use equity to acquire other companies. But given what's going on with Navigator Pipeline and looking at your potential future growth opportunities. Are you taking a closer look at strategic M&A and using equity given your stock and refiners in general have held up pretty well relative to other potential step-out opportunities? Thanks.
spk14: This is Lane again. I would say that we look at all these opportunities and all the business lines that I alluded to earlier. And we have an entire group, our innovation group, that's constantly looking at how can we bolt on and leverage our existing footprint, which obviously we have a big footprint in ethanol and we have a pretty big footprint in renewable diesel. Then we're also looking at everything else. Everything's on the table. We're always looking at it, but we're also very careful in terms of how we talk about it and how we're going to announce things. In terms of how we finance it, it's just a matter of when we, as the world evolves, we'll come up with the best way that we think to finance something. And obviously, all these things have to go through sort of our investment-gated process.
spk00: Got it. Thanks for the answers.
spk16: Thank you. The next question is coming from Roger Reed of Wells Fargo. Please go ahead.
spk04: Yeah, thank you. Good morning. Maybe to follow up on Mr. Gableman's question there, if we think about acquisitions, latest news says Citgo is is potentially gonna be on the auction block beginning of next year. So just curious how you think about a greater footprint within refining as any kind of a possibility.
spk14: So you know, hey, Roger, this is Lane. So you know our history. We were a big consolidator in the industry going back to 2000 up to really our last major acquisition was for the circuit 2013. That's when our base became somewhat like it looks today. We understand probably as well as any operator out there what it takes to buy something or to merge something and get it on our system and all the costs associated with it. We always look at everything that we think within reason. We always analyze everything. We haven't bought anything, like I said, since 2013, any refining assets. You never say never. We look at everything, and we'll, again, like I alluded to on Jason's question, we'll run it through our processes and figure out whether anything makes sense for us or not.
spk04: Yeah, I'd imagine the data room will be entertaining.
spk14: I just want to make sure I'm clear on that, Roger. They've got to compete with everything else, including buybacks, right? So, anyway.
spk04: Right, right. No, I mean, the data room is going to have to be interesting at a minimum. Second question I have, it's unrelated, but kind of a follow-up on some of the things going on on the renewable fuel side. We've seen a lot of downward moves, or we saw a strong downward move, I should say, in the D4, D6 RENs, kind of latter part of Q3 and the early part of Q4. Looks like the market's more or less sort of adjusting to that on some of the feedstock and other issues, but I was just curious if you all had any read-throughs on you know, what caused that decline and whether or not this decline sort of reflects current situation or is there more downside risk to RENs given demand date versus production numbers and obviously an increasing volume of renewable diesel coming in 24 from the industry?
spk19: Yeah, I think, you know, as I mentioned before, you know, there's this kind of constant talk about oncoming production, increased rates, startups, projects, that has always said at some point the D4 is going to be under pressure, especially since the EPA did not raise the D4 obligation in their last set rule. So, you know, what I think, though, is, you know, and then we combine that with there was this kind of a rush, I think, looked like to me kind of a rush to sell RINs in the third quarter with that narrative combined with that Russian announcement that they were going to ban exports, which kind of quickly evaporated. So there's, I think, kind of more of a temporary view that, you know, that the D4 RIN was going to drop even more. And like you've observed, it's kind of recovered, and fat prices have also since adjusted. We clearly see that, you know, biodiesel and veg oil RD is negative now. That's one of the things we've always said is that, you know, the lower CI waste oil play was always going to be more advantageous. So even at these lower credit values, we're still the advantage platform. So, you know, as you go into 2024, you know, obviously obligations all reset. It's hard to tell exactly, you know, where that's going to go. There's no doubt that, you know, RD will continue to grow. We do see that for us. You're going to see RD continue to grow. As we talked before, Canada is a big outlet, which, you know, takes a lot of this rent exposure away. And then you also obviously have the SAF project coming on, where we'll diversify into a different market. And if for some reason SAF doesn't work, that product also meets Arctic diesel grades that, again, go to Nordic countries and Canada. So there's no doubt that there's going to be a continued pressure on the RINs for both the D4 and D6. But our strategy has always been there's other markets that you can minimize the impact of that. And then with our platform, we're still the most advantaged from a cost and CI standpoint.
spk04: No, I appreciate that coastal advantage as always. Thanks, guys.
spk14: Thanks, Roger.
spk16: Thank you. Our last question for today is coming from Matthew Blair of Tudor Pickering Holt. Please go ahead.
spk11: Hey, good morning. Thanks for taking my questions. Circling back to the RD margins in Q3, are you able to quantify the impact from DGD2 fire on the reported 65 cent gallon EBITDA margin?
spk19: No, we usually don't give that kind of detail. I would say it wasn't large. I just kind of leave it at that.
spk11: Sounds good. And then on the refining side, could you talk about your product exports in Q3 and so far into Q4? And do you expect any negative impacts from this announcement from Mexico a couple days that they're looking to restrict refined product imports into the country?
spk07: Yes, I'll take the first part of it and then let Rich Walsh handle the second part. Our exports, if you look at the exports in the third quarter, we did 389,000 barrels a day, 281 a distillate, 108 a gasoline. Based on second quarter, the volumes are up. Based on historic numbers, they trended up as well to our typical export locations. Most of the gasoline went to Latin America, about 70% of the diesel to Latin America and about 30% to Europe, and those are remaining at those levels as we move into the fourth quarter.
spk03: Mr. Rich, I'll just answer the second half of it. On this decree that's an issue, it's actually rightfully aimed at import smuggling that's going on. So you have individuals that are trying to bring product gasoline, diesel into Mexico, but describing it as something that has a lower tariff, like a paraffin or something like that, and importing it in. And that's That's resulting in them getting a lower tariff. This decree is really focused in on that. For Valera, we're properly importing all of our gasoline and products, and we're paying the full and proper tariff for it. Also, all of our fuel comes out of our own system, and it's all high quality and meets the specs. We have a lot of interaction with the Mexican authorities. They're aware of the legitimacy of our operation, and so we don't expect this initiative to be an issue for us.
spk11: Sounds good. Thank you.
spk16: Thank you. At this time, I'd like to turn the floor back over to Mr. Bilar for closing comments.
spk13: Thanks, Donna. Appreciate everyone joining us today. And as always, if you have any further questions, please feel free to contact the IR team at the call. Thanks again, and everyone have a great day.
spk16: Ladies and gentlemen, thank you for your participation. This concludes today's event. You may disconnect your line to log off the webcast at this time and enjoy the rest of your day.
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