Greetings, and welcome to Valero Energy Corp. Fourth Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's fourth quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, 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 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 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 with the SEC. Now, I'll turn the call over to Lane for opening remarks.

Thank you, Homer, and good morning, everyone. We are pleased to report strong financial results for the fourth quarter and the full year. With the exception of our 2022 results, we delivered the highest fourth quarter and full year adjusted earnings in the company's history in 2023, demonstrating the earnings capability of our portfolio. Our refining system achieved 97.4% mechanical availability in 2023, which is our best ever. We also set a record for environmental performance and matched our previous record for process safety, illustrating the benefits from our longstanding commitment to safe, reliable and environmentally responsible operations. Now through organic growth of our wholesale system, we set an annual record for sales volume in 2023 at approximately 1 million barrels per day, demonstrating the strength of our branded and wholesale marketing network. We continue to pursue 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 for completion expected in the first quarter of 2025 for a total of $315 million, half of that attributable to Valero. With the completion of this project, DGD is expected to become one of the largest manufacturers of SAF in the world. In addition, we are pursuing shorter cash cycle projects that optimize and capitalize on opportunities to improve margins around our existing refining assets. On the financial side, we continue to honor our commitment to shareholders. We returned 73% of adjusted net cash provided by operating activities to shareholders through dividends and share repurchases in the fourth quarter, resulting in a 60% payout ratio for 2023, and last week, our Board approved a 5% increase in the quarterly cash dividend. Looking ahead, we expect refining margins to remain supported by tight product supply and demand balances. In the near term, product inventories ahead of the summer driving season are expected to be constrained with heavy industry-wide turnaround activity in the first quarter, providing support to refining margins. Long term, we expect global demand growth to exceed products supplied despite new refinery startups. In closing, our team's simple strategy of pursuing excellence in operations, return-driven discipline on growth projects, and a demonstrated commitment to shareholder returns has driven our success and positions us well for the future. So with that, Homer, I'll hand the call back to you.

Thanks, Lane. For the fourth quarter of 2023, net income attributable to Valero stockholders was $1.2 billion or $3.55 per share compared to $3.1 billion or $8.15 per share for the fourth quarter of 2022. Fourth quarter 2022 adjusted net income attributable to Valero stockholders was $3.2 billion or $8.45 per share. For 2023, net income attributable to Valero stockholders was $8.8 billion or $24.92 per share compared to $11.5 billion or $29.04 per share in 2022. 2023 adjusted net income attributable to Valero stockholders was $8.8 billion or $24.90 per share compared to $11.6 billion or $29.16 per share in 2022. The refining segment reported $1.6 billion of operating income for the fourth quarter of 2023 compared to $4.3 billion for the fourth quarter of 2022. Refining throughput volumes in the fourth quarter of 2023 averaged 3 million barrels per day. Throughput capacity utilization was 94% in the fourth quarter of 2023. Refining cash operating expenses were $4.99 per barrel in the fourth quarter of 2023, higher than guidance of $4.60 primarily due to an environmental regulatory reserve adjustment in the West Coast. Renewable Diesel segment operating income was $84 million for the fourth quarter of 2023 compared to $261 million for the fourth quarter of 2022. Renewable Diesel sales volumes averaged 3.8 million gallons per day in the fourth quarter of 2023, which was 1.3 million gallons per day higher than the fourth quarter of 2022. The higher sales volumes in the fourth 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 fourth quarter of 2022 due to lower renewable diesel margins in the fourth quarter of 2023. The Ethanol segment reported $190 million of operating income for the fourth quarter of 2023 compared to $7 million for the fourth quarter of 2022. Adjusted operating income was $205 million for the fourth quarter of 2023 compared to $69 million for the fourth quarter of 2022. Ethanol production volumes averaged 4.5 million gallons per day in the fourth quarter of 2023, which was 448,000 gallons per day higher than the fourth quarter of 2022. Adjusted operating income was higher than the fourth quarter of 2022, primarily as a result of higher production volumes and lower corn prices in the fourth quarter of 2023. For the fourth quarter of 2023, G&A expenses were $295 million, and net interest expense was $149 million. G&A expenses were $998 million in 2023. Depreciation and amortization expense was $690 million and income tax expense was $331 million for the fourth quarter of 2023. The effective tax rate was 22% for 2023. Net cash provided by operating activities was $1.2 billion in the fourth quarter of 2023. Included in this amount was a $631 million unfavorable impact from working capital and $65 million of adjusted net cash provided by operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.8 billion in the fourth quarter of 2023. Net cash provided by operating activities in 2023 was $9.2 billion. Included in this amount was a $2.3 billion unfavorable impact from working capital and $512 million of adjusted net cash provided by operating activities associated with the other joint venture member's share of DGD. Excluding these items, adjusted net cash provided by operating activities in 2023 was $11 billion. Regarding investing activities, we made $540 million of capital investments in the fourth quarter of 2023, of which $460 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member's share of DGD, capital investments attributable to Valero were $506 million in the fourth quarter of 2023 and $1.8 billion for 2023. Moving to financing activities, we returned $1.3 billion to our stockholders in the fourth quarter of 2023 of which $346 million was paid as dividends and $966 million was for the purchase of approximately 7.5 million shares of common stock, resulting in a payout ratio of 73% for the quarter. As Lane mentioned, this results in a payout ratio of 60% for the year. Through share repurchases, we reduced our share count by approximately 11% in 2023 and by 19% since year-end 2021. 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 $5.4 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 18% as of December 31, 2023. And we ended the quarter well capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2024 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, regulatory compliance, and joint venture investments. About $1.6 billion of that is allocated to sustaining the business and the balance to growth with approximately half of the growth capital towards our low carbon fuel businesses and half towards refining projects. Our low carbon fuels growth capital is primarily for the SAF project. Our refining growth projects aim to increase our crude flexibility in the Gulf Coast, extract more value out of some of our conversion unit capacity, improve our access to some key product markets, and improve our logistics into or out of our refineries. All of these projects meet or exceed our minimum return threshold of 25% after-tax IRR. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.52 million to 1.57 million barrels per day, which includes turnaround work on the legacy coker at our Port Arthur refinery; Mid-Continent at 415,000 to 435,000 barrels per day; West Coast at 235,000 to 255,000 barrels per day; and North Atlantic at 435,000 to 455,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $5.10 per barrel, reflecting lower throughput due to turnaround activity across our system. With respect to the renewable diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2024. Operating expenses in 2024 should be $0.45 per gallon, which includes $0.18 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.5 million gallons per day in the first quarter. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $150 million, and total depreciation and amortization expense should be approximately $700 million. For 2024, we expect G&A expenses to be approximately $975 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.

Our first question today is coming from John Royall of JPMorgan. Please go ahead.

Hey, good morning. Thanks for taking my question. Good morning. So my first question is on the macro side, just on light heavies. LLS-Maya has risen all the way to around $10 from about $6 beginning in the quarter, yet we still have OPEC being restrictive in terms of production. Can you talk about the drivers of the widening of coastal heavy diffs and how you see them progressing from here?

Sure. This is Gary. I think a number of factors contributed to that. You did see production in Western Canada tick up a little bit in the fourth quarter. We're seeing a few more Venezuelan barrels make their way into the U.S. Gulf Coast. So a little more supply on the market. But probably the biggest factor is as you got late in the fourth quarter and early this quarter, you're starting to see the impact of turnarounds decreasing demand for some of those, especially the heavy sour barrels. In addition to those factors, you had the typical seasonality in high sulfur fuel oil, but lower high sulfur fuel demand for power generation kind of weighing on the heavy sour discounts as well. So our view is that through the first quarter, through refinery maintenance season, you'll continue to see a little bit wider heavy sour discounts, but then you'll start to see those come in and really for any meaningful impact to sustainable impact for the quality diffs we need more OPEC production on the market. If you look at the consultant forecast, it looks like that could happen probably third quarter this year.

Great. Thanks, Gary. And then my second question is on return of capital. So your number for the quarter was very strong, and you finished the year at 60% of CFO. I know you've talked about how you tend to come in above the range when cracks are strong. If '24 ends up being kind of more of a mid-cycle type year or even below, how should we think about where you might fall in that 40% to 50% range this year?

Good morning. This is Jason. And I've got a bit of a cold. And if I talk too much, I'll go into cough fits, so I'm going to ask Homer to respond.

Thanks, Jason. Yes, John, I mean our approach to shareholder returns is driven by our annual target of 40% to 50% of adjusted net cash from operations. And obviously, that includes the dividend, which we consider non-discretionary, and buybacks, which are considered the flywheel supplementing our dividend to hit our target. And given the strength in our balance sheet in the fourth quarter, as we highlighted, we had a 73% payout which resulted in a 60% payout for the year. And as you touched on, since 2014, we've regularly paid above our target. And in fact, the average payout for the five years leading into COVID was around 57%. So I think in short, in periods when the balance sheet is strong as it is right now and sustaining CapEx, the dividend and strategic CapEx is covered. You can reasonably think of our 40% to 50% target as a floor and expect any excess cash to go towards buybacks.

Thank you.

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

Good morning. Would you mind giving us an update on your clean products supply and demand outlook from here? Taking into account the recent inventory moves as well as the additional refining capacity ramping up internationally, some utilization even is not fully running, and what you're also seeing in terms of demand across your footprint, please?

Sure, Theresa. This is Gary. It's always difficult to assess the markets this early. Kind of the holidays and weather tend to have a big impact on road transportation fuel demand and then fog in the Gulf kind of tends to limit exports. But domestically, I can tell you demand for gasoline appears to be following typical seasonal patterns. It looks normal for this time of year and in line with where we were last year. I will tell you, gasoline volumes through our wholesale channel of trade are down a few percent year-over-year. We're not really concerned about that because you can see it’s in regions that were really impacted by weather. And as the weather we're starting to see the volumes recover nicely. European gasoline markets are relatively strong. That's kept the transatlantic arb closed, and the market structure doesn't really incentivize making summer-grade gasoline and putting it into storage. Gasoline exports into Mexico and Latin America have remained steady. So all of this has us pretty optimistic on gasoline cracks once we move into spring and gasoline demand improves with the driving season. On the diesel side, demand in our system is up about 7% compared to last year. Probably seeing more heating oil demand with a little colder weather. Diesel inventory remains at the bottom of the 5-year average range. So good demand combined with low inventory continues to support the diesel cracks. Diesel exports in our system were down a little in the fourth quarter. The Russian barrels making their way into South America have caused some changes in trade flow with more of our barrels going to Europe. In Europe, warm weather tended to keep their demand down a little bit. But I can tell you thus far in the first quarter, we're seeing much stronger European demand with the colder weather hitting there. We believe the diesel cracks continue to get support from increased jet demand. As kerosene gets pulled out of the diesel pool as we continue to recover from COVID. Jet demand last year was still down about 10.5% from pre-COVID levels. Most forecasts show us closing about half that gap this year. And then expectations for a little better for diesel demand with slightly colder weather and freight picking back up as well. So overall, back to your question on new capacity, it looks like to us somewhere about 1.5 million barrels a day of new capacity coming online, year-over-year growth in demand looks to be slightly over 1 million barrels a day. So supply/demand balances are really fairly close to what we saw last year. The question really becomes timing of when that new capacity comes on. Our view is that it will take longer for those new refineries to start up, and you don't really see an impact on supply until later in the year. And if that holds, then you have relatively tight supply-demand balances with really the only difference being we're starting from a different inventory position, as you've already mentioned. In our mind on that, we do expect to see inventory draws over the next several weeks. The cold weather had some impact on refinery operations, and then you'll start to get into turnaround season, which we would expect total light product inventory to begin to draw.

Thank you for that detailed answer. And then maybe just looking within the U.S., what are your views on the divergence in product margins across regions? What do you think is causing the weakness in benchmark cracks in the Mid-Con particular just suppose with the strength in the Gulf Coast?

Yes. So historically, we've seen that the Mid-Con is short product in the summer and long product in the winter. And I think we're seeing that this year. The market is just long, and especially the weather has tended to hit that region more, and so we see demand off in that region. But I think once you start to see the weather clear and you get back into driving season, the Mid-Continent will recover. We're seeing the same thing kind of on the West Coast; the weather has tended to impact demand on the West Coast. And so we've seen that market a little bit softer than maybe you would typically see for this time of year.

Thank you.

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

Yes. Congrats on great results. And one of the things that stood out to us was the capture rates continue to be very good. And I recognize some of that is operational performance, but some of that's commercial, and Lane guaranteed, I know there's some sensitivities around that, but a lot of your competitors spend a lot of time talking about what they're doing on the commercial side. So just be curious, if anything you can share about how you're optimizing what continues to be a very dynamic environment.

Hey, Neil, it's Lane. So I'm not going to, you know, I'll start by saying thank you. And I will say that, you know, I wouldn't trade our commercial team for any other team in the industry. I sort of spoke about this in the past. You know, everyone in our company understands the position they play. I think sometimes some, I've been in organizations where that's not really clear and you can get a lot of interference running between the supply chain. That's not true at Valero. Everybody has a position they play and they understand how to do it well. Refining focuses on reliability and operating envelopes and expenses, our P&E coordinates between the groups that make the signals, and our refining commercial groups execute the signals. And it's pretty clear on how all that's supposed to work. And so I would tell you that that's really the key to our execution. And, of course, finally, everybody in the corporation is incentivized with the same goals. We don't have different groups having their own sort of incentives. So that's how we get alignment all the way through. So glad to have them.

Yeah, no, it shows up. So thank you. Then the follow-up just on North Atlantic, it was particularly strong this quarter relative to the benchmark. You know, the benchmark, I think, was $16, and the realized gross margin was well above that. So just curious if there's anything you'd call out in Montreal or UK that drove the strength there.

Hey, Neil, this is Greg. So we saw accrued costs improve in that region, primarily in Cannes, where you saw that occur more than you did in Pembroke. And then you brought up commercial margins. They were very strong for the quarter as well for that region. And then some of the compliance costs for the programs over there, costs were lower than we've seen in prior periods. And all those things combined to drive up that capture rate in the North Atlantic.

Yeah, and I'll just add, you know, Syncrude trading at $7 below Brent, and a discount to that to Brent with a high distillate yield crude is a real benefit to our system.

Yeah, that makes sense. Thanks, guys. Thanks.

Thank you. The next question is coming from Doug Leggate of Bank of America. Please go ahead.

Hey, guys. Good morning. Thanks for taking my questions. I'm not sure who wants to take this one, Lane, but I want to ask perhaps an obvious question about shipping disruptions and what it means for perhaps not Valero specifically, but just in a more macro sense. How do, you know, the situation with the Red Sea bidding up clean tanker rates and so on, what does that do to the movement of product and the implications for a system which is perhaps more dependent on imports than it has been at any time, at least since I've covered this sector?

Yeah, so, you know, we're not really running crude from that region, so it hasn't really had an impact on us in terms of supply of crude. But the big impact, especially on the crude side of the business, has just been freight rates. You know, we had a period of time where you could export from the U.S. Gulf Coast to Northwest Europe crude, you know, in the low $2 a barrel range. That spiked to $6 a barrel. And you could see that in Brent TI. So, you know, I would tell you probably for our system, net is an advantage because it gives us a crude cost advantage versus our global competitors.

Okay. I realize it's kind of hard to quantify, so we'll continue to watch, but thanks for that answer. Lane, my follow-up is for you or maybe for Jason, given it's cold, but 40% to 50% payout, it seems that, at least on our numbers, you are easily able to sustain the payout at the higher level, especially now that you've restated your $2 billion CapEx plan. So I'm just curious, what's the rationale to kind of reset that range that your system clearly is capable of supporting in terms of the payout?

I'm going to let Homer answer that.

Hey, Doug. I mean, I think obviously our target is set on a long-term range, right? And so the 40% to 50% think of it as like a long-term target. But to your point, and as I mentioned earlier, we've consistently come in above that. And, again, I think when you have a strong balance sheet as it is right now, we're not going to build cash. So I think you should reasonably expect shareholder returns to come in above that target.

That's what we expect. Thanks so much. I appreciate you taking my questions, guys.

Thank you. The next question is coming from Manav Gupta of UBS. Please go ahead.

So I wanted to ask about the renewable diesel side of the business. The capture on the DJD dropped to about 49%. And now Homer has done a very good job of explaining to the market how the lag works. So if we add back that lag effect and that 64%, the actual capture would have hit something like 93%. So when we look past 4Q, the margin is up materially. And if we assume an 80%, 90% capture, ignoring the lag, would that imply that first quarter in terms of renewable diesel margin would be much stronger than the earnings that came for the fourth quarter?

Hey, Manav. This is Eric, and I would just say yes. Yeah, that's a very good – yeah, we see a lot of the same curve that you described. And really the change for renewable diesel for Valero is with the first full year of DJD3 in operation, we run a lot higher percentage of foreign feedstocks, and that supply chain is just naturally longer. So the most attractive, lowest CIA feedstocks are coming from foreign imports, and I think that's creating this longer lag than we've seen in DJD historically. So your analysis, I think, is correct.

Perfect. Thank you. Just a quick follow-up here is last year we had an abnormally warm winter. Now when we look at this first quarter, as you guys have mentioned, the industry is taking a heavier turnaround versus last year, and then you could have a much colder weather out, as we are all seeing there. So year-on-year comp for the first quarter, again, could be better than even last year. I'm just trying to understand the dynamics versus last year versus this as it relates to the heating oil demand.

Yeah, that's kind of the way we see it. The big difference between last year and this year is we had the winter storm early in the quarter last year, which took refining capacity offline and kind of created the big inventory reset. You didn't have that this year, but then in our mind you'll see more of a draw as we get into February and March with the turnaround activity and a little colder weather.

And it's January. So we still have the possibility of cold weather hitting the Gulf Coast.

Thanks, guys.

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

Hi. Morning, everybody. Thanks for taking the question.

Good morning.

I had a question on the gasoline market. You know, I think capture rate in 4Q may have benefited from butane economics, and so correspondingly if there was a high incentive to blend as much winter grade as possible, there may have been a low incentive to make and store summer grade, and there's just a lot of NGL supply that is kind of making its way into stockpiles across a number of categories. And so I want to know if it makes sense to think about, you know, as we enter into driving season, if total gasoline inventories are maybe overstated, just given the quantity of, you know, maybe butane in that number.

Yeah, certainly in our system when you look at the cost to produce a summer grade of gasoline, there's no economics at all to be making summer grade gasoline and putting it into storage. You know, I think the only people that could be storing barrels at all would be high octane components, and they're really just speculating that octane is going to get stronger. But we certainly see it that way; the barrels that are in storage today are largely winter grade.

Great. And thanks. My non-follow-up second question is about SAF. And, you know, I'm just wondering how that market is developing for you commercially, you know, as we get closer to the SAF unit coming on. I think there's a view that, you know, the SAF market could take on some, you know, contracted, you know, longer-term kind of cost plus characteristics because airlines have levers to pass it through that are sort of outside of the policy regime. But would love your thoughts on how commercially SAF is developing as you get closer to production.

Yeah, Sam, I think you've said it well. We continue to talk to all the airlines and cargo carriers. A lot of their models are going to be based on more of a voluntary approach in sort of a jet plus basis that goes into a pass-through to customers that want to offset their carbon footprint through their travel budgets. And so we continue to have a lot of those conversations. I think we're very close on having several contracts done with airlines going into our early production from our project. So that continues to be progressing very, very well. So we don't see that we're going to have a problem moving all of the volume out of this project.

Awesome. Thank you so much.

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

Morning all. I was going to ask about international shipping, but you've dealt with the Red Sea. So could you just talk a bit about Russia? There were big headlines about a port explosion there. I was wondering how much distillate and other product you're seeing coming out of Russia as we start the year. Secondly, I think you've benefited a lot from Venezuelan incremental Indonesian crude. What's your outlook there? And then finally, what are you seeing from Mexico with the new big refinery starting, and Nigeria maybe with the refinery starting? Thanks.

Okay. Yeah, I'll start with Russia. I think, you know, the drone attack that occurred last night, probably the biggest market impact we're seeing so far is you've seen a reaction in the naphtha market. That refinery supplied a lot of naphtha to the Far East, and so there's concern that that flow may be gone, and so the naphtha market's tightened up. I think you do see distillates starting to fall, you know, and some of what we're seeing is that, you know, as the refineries experience some issues, they're having trouble getting support from the West that they typically would, even for things like, you know, spare parts and those types of things. So, you know, we do see that maybe distillates start to trend off a little bit due to those issues. The middle part of the question was?

Venezuela.

Okay, yeah. So we continue to ramp up our volume of Venezuelan crude. I think, you know, the lifting of sanctions more than additional volume into our system probably had more of a price impact, you know, so we did see a little bit more value in the fourth quarter on the Venezuelan barrels that were running as a result of, you know, further reducing some of the sanctions that they have on Venezuela.

Mexico refineries, though.

Yeah, so we're not seeing any impact as of yet from the Mexico refineries. You know, when we talk about crude supply, there's always the discussion that, you know, we may see some fall off in our supply of Maya, but that really hasn't impacted us yet. And we don't see any delta on the product side of the business yet either.

And I guess that would then apply to Nigeria as well, right?

Yes, same thing. We think in our mind, it's going to take a while for that refinery to ramp up. It's just a big refinery that's not going to be easy to bring online.

Great. And then just a follow-up second question here, Homer. Lane, you said that you don't anticipate the asset base changing greatly with the change that we saw last year in CEO with you taking the leadership. Can you just update us, given the number of assets that are on the market? And perhaps if you want to add anything on California where results look weak for the quarter, and you've expressed dismay about policies there? Thanks, I'll leave it there. Thanks.

Yes. Joe and the leadership team have been consistent. We evaluate everything that enters the market. Our perspective is shaped by the desire to move away from fossil fuels as seen in policies in Europe, Canada, and the United States, along with the challenges of making investments. We perceive transportation fuels to be structurally short. This lens informs our assessment of incoming assets. Since the 2000s, we have been the leading consolidator in the industry, so we understand the necessary dynamics and excel at it. We approach new assets with a comprehensive understanding of costs and weigh them against organic growth and share buybacks. We appreciate our asset base, although operating in California is increasingly challenging. Additionally, we continue to evaluate all opportunities, including refineries.

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

Yes. Good morning. I would like to follow up with you on summer grade gasoline. I understand that the inventories are not significant, but what do the incentives look like at this time? Or are we nearing the conversion in March, which means the seasonality of gasoline is already established? I'm trying to grasp how the market will balance heavy maintenance with the current market conditions.

Yes. So our view, Roger, you look and there's about $0.10 a carry to the March/April screen. We would tell you the cost to produce, with butane being cheap, is closer to $0.20, so certainly, no economic incentive at all to store gasoline. A lot of what we think happened in terms of the inventory build is that you had a lot of things happen in December, especially in the Gulf Coast. Colonial was allocated the economics to ship on Explorer into the Mid-Continent; that arb was closed due to the Mid-Continent being weak. You had some Jones Act freight off the market in dry dock that limited some movements there. And then a lot of volatility in the freight markets really impacted exports late. And so what you saw is Gulf Coast inventories draw, and in our mind, the Gulf Coast basis got weak enough that although there wasn't carry on the screen to keep gasoline inventory, I think we saw a lot of refiners choosing to hold inventory just because the U.S. Gulf Coast basis was so weak, and they chose to store barrels that they would go ahead and then consume during their own maintenance periods rather than going out and covering and saw better value to do that. So if that's the case, then you should see this inventory work off over the next couple of months.

That's helpful. In renewable diesel, there are some feedstock issues this quarter, and new capacity is coming online. I'm curious about how we should view margin potential in this business, considering the current market structure or the forward curve. Can you help us understand the various factors at play, especially regarding the feedstocks and their timing in relation to daily market matching? It seems a bit unclear to us.

Yes. The outlook for renewable diesel is challenging to predict due to increasing capacity coming online, which may lead to a decrease in credit values for both RINs and LCFS, ultimately impacting RD margins. However, we also observe that feedstock prices are decreasing, both in waste oil and vegetable oil. Waste oils inherently provide a better carbon intensity advantage compared to vegetable oils, meaning that while vegetable oils might be more abundant, they will not be competitive against waste oils in compliance markets. The foundation of our DGD business relies on being a low-cost producer of waste oils and having access to markets beyond California. Therefore, we believe we remain competitively advantaged in terms of operational costs and feedstock sourcing. Overall, we expect credit prices to continue to narrow, and we are uncertain about how feedstock prices will respond to that. Additionally, by diversifying sales away from California and into sustainable aviation fuel, which will reduce our dependency on the renewable diesel market, we believe these strategies will keep us as the most competitive and advantaged platform in renewable diesel, even as the market tightens.

So is it fair to summarize that as there's probably a lot more clarity on, let's call it, the supply side of R&D this year and a lot less clarity on the feedstock side? In other words, where we should look for relative opportunity is probably on your feedstock rather than, say, the sales price of R&D?

Yes, I think that would be fair to say that most of that is still being a CI advantage in waste oils over vegetable oils.

Right, okay. Appreciate it. Thank you.

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

Thanks. I have a question regarding the turnaround activity appearing quite significant in the first quarter. Should we anticipate a higher level of overall maintenance for you in 2024, primarily front-loaded? Additionally, what insights can you share about the overall industry maintenance activity this year? Should we expect another relatively heavy year?

Ryan, this is Greg. Normally, we don't talk about our overall turnaround plans. You can tell from the guidance, a fair amount of activity for us in the first quarter. I think when we get out through the rest of the year, we'll talk about those periods as we come up to the. I think from an industry perspective, we are seeing a fair amount of turnaround activity across the industry in the first quarter. So in kind of to Gary's point, it looks like it's going to be a heavy season for the industry in general, a lot of it in the Gulf Coast, with a lot of focus there.

The only other thing we may add is although you can see the throughput guidance, we don't really expect it to impact our capture rates. That's right.

Thank you. I'd like to ask a follow-up question regarding capital expenditures and growth capital expenses. I appreciate the details you provided about the factors affecting your growth capital budget. Most of your major project-driven work has recently concluded, and the SAF project isn't particularly large. As we look ahead, are there any significant environmental or regulatory factors we should monitor over the next couple of years that might require additional capital? Or should we anticipate more small, netback-driven projects in the refining sector in the coming years?

Hey Ryan, it's Lane. The way I would think about this is if you go back when we historically, we used to sort of spend, I would say, we said $1.5 billion sustainable capital. That would actually include regulatory capital. I mean that's how we frame it. It sort of maintain our assets to generate the earnings we're supposed to and try to work your sustain of your regulatory capital in that, albeit it would be lumpy. And so you're going to average around that number. So that's how we think about the regulatory side of it. I don't really foresee, at least right now, that we have a large regulatory spend. Clearly, that could always change. In terms of our strategic capital, historically, we were around $1 billion. As an organization, we felt like we can execute $1 billion pretty well. We have some experience over 10 to 11 years ago where we spent more on strategic capital, and then it was sort of difficult to manage. And so we, as an organization, we decided that we're going to live within a sort of $1 billion on the upside of strategic capital. Since COVID, we've been at about $0.5 billion, and that's our guidance right now. And we feel like that's a pretty good number year-in and year-out that we're going to steward around that will be enough projects, whether they're in refining or transportation or our renewable platforms that all meet and work through our gated process to meet our return thresholds.

Okay. Thanks.

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

Hey guys, good morning. I just don't know whether this will be Lane or Gary. If we're looking at octane last year that was very strong. If this year that I think a lot of people expect because after last year, the global gasoline demand growth rate probably will slow down; China is definitely slowing down. And I think the U.S. may even go into a structural, because if that will be the case, how do you expect the octane lending is going to look like? And what kind of impact or what kind of impact is on your financial results?

Okay. Yeah. So I would say a couple of things on octane. Certainly, the incremental crude barrel that's been coming on to the market has been a light sweet barrel, which has created more naphta yield coming on to the market. And with pet-chem demand being somewhat down, that incremental barrel of naphta that's being produced is trying to find its way into the gasoline pool. And so what that does is it really causes octanes and naphthas to trade at an inverse; when naphtha gets long, naphtha gets weak, and then octane starts to trade at a premium. So you can try to blend that naphtha barrel into the gasoline pool. I don't know that we see that being significantly different this year. The one thing I would tell that I've already mentioned, if there's a prolonged outage in Russia at the refinery that was hit by the drone attack, and there's less naphtha out on the market. That could tell you that octanes tend to be a little bit weaker this year. But absent that, I don't see any fundamental differences in the naphtha or octane markets. Greg, I don't know if you have anything?

I agree.

And Gary, are you guys net long or balanced on octane?

It varies. I would say we're fairly balanced on octane. We're long naphtha, so you can always soak up octane that way. But overall, in octane, I'd say fairly balanced.

All right. And Gary, Greg, that you guys have a marketing operation in Mexico and in the Caribbean. In Mexico, any insight how does the local demand look like?

Yeah. So our business there continues to grow very, very nicely. Year-over-year, our volumes were up 16% in Mexico. We now have 250 branded sites, which was the largest growing brand in Mexico. I think the big change for this year is in the second quarter of this year, we anticipate the terminal that we'll use in Northern Mexico and Altamira will start up, it will allow us to be more competitive in that region, which we would expect us to then be able to continue the growth that we've seen.

How about outside your operation, but that the market as a whole, do you see the gasoline market in Mexico is growing or that is maybe a little bit pullback?

Yeah. So our view is Mexico basically recovered last year to pre-COVID levels. And our expectation is you'll see continue to see good growth in the gasoline market in Mexico.

The next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead.

Hey, team. Good morning. And thanks for my questions. So I wanted to start off going back to an earlier point, you mentioned some of the cold weather on the Gulf Coast in the past couple of weeks. Were there any material impacts to operations or crude and product price dislocations that we should be mindful of for the first quarter?

No. I would tell you, we had some small operational issues, boiler trips, heater trips, but nothing that's going to materially impact the quarter and we still feel like the throughput guidance that we've given holds.

Great, thanks. And then shifting to renewable diesel. So volumes averaged above nameplate capacity for the year, which is good to see. It seems like a consistent theme about performance there. Any reason why we shouldn't expect a similar level of outperformance in 2024, such as turnarounds or anything?

Yeah. I think we kept the guidance at the $1.2 billion. We've got a couple of catch changes this year. And obviously, when we convert to SAF, there could be a change in capacity because we do have to run the unit a little harder in that mode. So we're not sure what capacity will look like to that until we get the project on the ground and start it up. So I think this time next year, we'll have an outlook of what our capacity guidance will be whether it's up or down.

Got it. That makes sense. Thank you.

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

Good morning, and thank you for taking my questions. My first question is regarding refining operating expenses. It seems the market has not been as focused on this metric in recent years due to strong margins, but it may become more significant as margins normalize. Historically, your refining operating expenses were about $3.50 per barrel, but this year they seem to be around $4.50 per barrel, even with similar Henry Hub prices to previous years. What factors have contributed to the increase in operating expenses this year compared to pre-COVID levels, and do you anticipate them remaining high or decreasing in the future?

Hey, Jason, this is Greg. So one of the things that's probably most notable when you think over that period has been electricity prices that not so much natural gas, but on the power side. A lot of the places where we operate have seen power costs, particularly in the summer, be quite a bit higher than we'd seen historically. So that's a part of it. The other part that thinking back over that time frame would also be more recently, some cost inflation pressure, and we've talked about that a few times before. That seems to be easing. So that's something we're working on to rein back in with our suppliers and folks that we work with.

Is there Jason, this is Lane. I will say still the lowest cost guide, and we work on this like you cannot imagine you should know that as an organization, we're committed to making sure that we are the best in class with expenses.

Yeah. No, we carefully said that is there any expectation to get back down below $4 or is this kind of $4.50 range we should think about moving forward? Yeah, I'm on cue.

We'll review the numbers. One of the primary factors influencing our throughput, despite having both variable and fixed costs, is that most refining expenses are largely fixed. Therefore, the more barrels we process, the more favorable that metric becomes. The third quarter is the ideal time to assess this and truly grasp the system's performance. Typically, this is when we can operate at maximum capacity, with all systems functioning and costs stabilized. It's the best opportunity to understand the baseline operational expenses for the system.

Got it. My other question is on the refining growth CapEx, and you rattled off a bunch of what seems like quick-hit projects that clear your return hurdles. Is there a way you could kind of frame these projects together in terms of potential improvement to capture and kind of whatever stable margin environment you would evaluate that on or any type of way you could frame the potential upside from these projects? Or is it alternatively just keeping capture maybe stable and enabling flexibility to keep capture stable? Thanks.

I believe we are going to make an effort to provide more clarity in our investor relations presentation to showcase the success of many of our projects in the growth process. However, we remain disciplined and avoid overly forward-looking discussions about projects, regardless of their scale. What we aim to demonstrate is that our process yields returns, and currently, we have approximately $0.5 billion in annual spending that we believe will yield returns as it progresses through our gated processes.

Understood. Thanks, Jas.

Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.

Hey, thanks for the commentary on light-heavy earlier. I believe Valero runs about 200 a day of WCS at Houston in your Gulf Coast system. Is that correct? And is there any risk to that availability with TMX starting up soon?

Our Canadian volumes fluctuate, typically around 500,000 to 600,000 barrels a day. We can balance supplies from Mexico, Venezuela, and Canada. We believe that TMX will allow Gulf Coast barrels to continue flowing from Western Canada, but it will mainly reduce exports from the U.S. Gulf Coast. We don't anticipate that our Gulf Coast system will be significantly affected by TMX.

Thank you. I have another question regarding capital returns. Considering the strong buybacks in Q4 and an impressive payout ratio of 73%, I found it interesting that your cash balance increased year-over-year in 2023. It appears you started the year with around $2 billion in excess cash and ended with approximately $3 billion. Can you explain why this occurred? Were there any limitations on buybacks or restrictions in the market? Additionally, regarding the $3 billion in excess cash, do you have internal targets for potentially using $1 billion or $2 billion of that in 2024?

Yeah. Hey Matthew, it's Homer. I mean I think, first of all, we're comfortable with where we are from a cash balance perspective. But we've discussed in the past, we like to stay above $4 billion. We had a very, very strong payout, right, particularly for the quarter, but then also for the year. In terms of paying down, like, for example, we look at debt right on the debt side, we proactively look at our portfolio through a liability management lens. And so given the strength of our balance sheet, we don't really currently have any pressing need to pay down debt with a net debt-to-cap ratio of 18%. But it's an ongoing evaluation, and it's something that we look at.

And just to clarify, you said your minimum cash balance is now $4 billion.

We like to stay above $4 billion.

We made some changes over the last couple of years as we emerged from COVID. Before the pandemic, we aimed to reduce our minimum cash balance to $2 billion, but we realized that was too low. Now, we've opted to set our minimum cash balance closer to $4 billion. The advantage of maintaining a $4 billion balance compared to $2 billion is that we can actually earn a return on that cash, which wasn't possible before. This decision is influenced by our experiences during COVID.

Okay. That’s helpful. Thank you.

Thank you. This brings us to the end of the question-and-answer session. I would like to turn it back over to Mr. Bhullar for closing comments.

Thanks, Donna. That concludes our opening remarks. If you have any follow-up questions, please feel free to reach out to us at the IR team. Thank you once again for joining us, and have a wonderful week.

Ladies and gentlemen, thank you for your participation and interest in Valero. You may disconnect your lines or log off the webcast at this time, and enjoy the rest of your day.