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At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone requires 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, Brian Donovan, VP Investor Relations. Thank you. You may begin.

Good morning, everyone, and welcome to Valero Energy Corporation's first quarter 2026 earnings conference call. I'm joined today by Lane Riggs, Chairman, CEO, and President, Gary Simmons, Executive Vice President and COO, Rich Walsh, Executive Vice President and General Counsel, Homer Bhullar, Senior Vice President and CFO, as well as several other members of Valero's senior management team. If you have not yet received a copy of our earnings release, it is available on our website at investorvalero.com. Included with the release are supplemental tables providing detailed financial information for each of our business segments, along with reconciliations and disclosures for any adjusted financial metrics referenced during today's call. If you have questions after reviewing these materials, please feel free to reach out to our investor relations team. Before we begin, I'd like to draw your attention to the forward-looking statement disclaimer included in the press release.

In summary, it says that statements made in the press release and during this conference call that express the company's or management's expectations or forecasts of future events are forward-looking statements and are intended to be covered by the safe harbor provisions under federal securities laws. Actual results may differ from those expressed or implied due to various factors which are outlined in our earnings release and filings with the SEC. I'll now turn the call over to Lane for opening remarks.

Thank you, Brian. Good morning, everyone. I'm pleased to report that Valero had an excellent first quarter, demonstrating our team's ability to optimize our refining system and deliver strong financial returns. In a period marked by considerable disruption in the commodity markets, our operations and commercial teams executed well. Early in the quarter, the availability of incremental Venezuelan supply resulted in wider crude differentials. Our advantaged Gulf Coast refining network was well-positioned to benefit from the discounted heavy sour feedstocks. Market conditions shifted sharply in March as the global supply of crude and refined products tightened. Our operations team responded decisively, adjusting the product slate to reflect market signals, delivering a record monthly jet yield. At the same time, our commercial and financial teams proactively managed commodity risk to mitigate any adverse impacts of a highly dynamic pricing environment.

Financially, we maintained a strong balance sheet while continuing to honor our commitment to shareholder returns. On the strategic front, we continue to make progress on the FCC unit optimization project at our St. Charles refinery. This $230 million initiative will enhance our ability to produce high-value products, including alkylate. We expect the project to begin operations in the third quarter of 2026. Looking ahead, constrained global refining capacity and low product inventories in key markets should continue to support refining fundamentals. Our concentration on high-complexity coastal refineries provides significant feedstock flexibility and direct access to global markets, which are especially beneficial in the current environment. Additionally, our disciplined financial strategy and capital allocation framework position us to perform well across market cycles. In closing, our strong performance in a volatile first quarter underscores Valero's operational, commercial, and financial strength.

We remain focused on things we can control. Operational excellence, system-wide optimization, and disciplined financial decision-making. The disciplined execution across these priorities positions us to benefit from the current margin environment and will continue to differentiate Valero. With that, I'll turn the call over to Homer.

Thank you, Lane. For the first quarter of 2026, net income attributable to Valero stockholders was $1.3 billion or $4.22 per share, compared to a net loss of $595 million or $1.90 per share for the first quarter of 2025. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the first quarter of 2025 was $282 million or $0.89 per share. The refining segment reported $1.8 billion of operating income for the first quarter of 2026, compared to an operating loss of $530 million for the first quarter of 2025. Adjusted operating income for the first quarter of 2025 was $605 million.

Refining throughput volumes in the first quarter of 2026 averaged 2.9 million barrels per day. Refining cash operating expenses was $5.13 per barrel in the first quarter of 2026. The renewable diesel segment reported operating income of $139 million for the first quarter of 2026, compared to an operating loss of $141 million for the first quarter of 2025. Renewable diesel segment sales volumes averaged 3 million gallons per day in the first quarter of 2026. The ethanol segment reported $90 million of operating income for the first quarter of 2026, compared to $20 million for the first quarter of 2025. Ethanol production volumes averaged 4.6 million gallons per day in the first quarter of 2026.

G&A expenses were $285 million for the first quarter of 2026. Depreciation and Amortization expense was $840 million for the first quarter of 2026, which includes approximately $100 million of incremental depreciation expense related to ceasing refining operations at our Benicia Refinery. Net interest expense was $140 million, and income tax expense was $401 million for the first quarter of 2026. The effective tax rate was 23%. Net cash provided by operating activities was $1.4 billion in the first quarter of 2026. Included in this amount was a $303 million unfavorable impact from working capital and $102 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 $1.6 billion in the first quarter of 2026. Regarding investing activities, we made $448 million of capital investments in the first quarter of 2026, of which $404 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 share of DGD and other variable interest entities, capital investments attributable to Valero were $430 million in the first quarter of 2026. Moving to financing activities, we remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $938 million in the first quarter of 2026, resulting in a payout ratio of 59% for the quarter.

On January 2second, our board approved a 6% increase to the quarterly cash dividend, reflecting a strong financial position and our commitment to a growing dividend. Turning to the balance sheet, in March, we opportunistically issued $850 million of 10-year notes at a 5.15% coupon to de-risk upcoming debt maturities later this year. The notes priced at a refining sector record low 10-year spread of 102 basis points over treasuries. At quarter end, we had $9.2 billion of total debt, $2.3 billion of total finance lease obligations, and $5.7 billion of cash and cash equivalents. Our debt to capitalization ratio, net of cash and cash equivalents, was 18% as of March 31, 2026.

Our cash balance was higher at quarter-end, reflecting the opportunistic timing of the March debt issuance and our decision to move towards the high end of our long-term $4 billion-$5 billion cash target to preserve optionality in a volatile market environment. Overall, we ended the quarter well-capitalized while still honoring our commitment to shareholder returns. Turning to guidance. As we operate the Port Arthur Refinery at reduced rates, we continue to assess the full extent of the damages and develop a plan for repairs. We expect the incident to result in additional capital expenditures in 2026, which should be covered by insurance subject to our applicable insurance deductibles. We'll update our 2026 capital investment guidance when we are able to provide a definitive cost estimate and expected repair timeline.

Outside of Port Arthur, our previous guidance regarding capital investments for sustaining the business and growth projects remains unchanged. Our growth projects are focused primarily on shorter cycle optimization investments that enhance crude and product optionality across our refining system, as well as efficiency and rate expansion projects within our ethanol plants. Collectively, these projects should strengthen the earnings capacity of our existing asset base. For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.69 million-1.74 million barrels per day, reflecting reduced rates at Port Arthur. Mid-Continent at 450,000-470,000 barrels per day. West Coast at 120,000-130,000 barrels per day, reflecting the idling of Benicia.

North Atlantic at 480,000-500,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $4.85 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 320 million gallons in the second quarter. Operating expenses should be $0.46 per gallon, including $0.22 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.7 million gallons per day in the second quarter. Operating expenses should average $0.39 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. For the second quarter, net interest expense should be about $145 million.

Total depreciation and amortization expense in the second quarter should be approximately $730 million, which includes approximately $33 million of incremental depreciation expense related to our plan to idle the processing units and cease refining operations at our Benicia Refinery completed this month. We expect incremental depreciation related to the Benicia Refinery to be included in D&A through April. The second quarter earnings impact of this incremental depreciation is expected to be approximately $0.09 per share based on current shares outstanding. For 2026, we expect G&A expenses to be approximately $960 million.

Thanks, Homer. That concludes our opening remarks. Before we open the call to questions, please limit 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.

Thank you. The floor is now open for questions. Today's first question is coming from Manav Gupta of UBS. Please go ahead.

Good morning, guys. Very strong quarter considering everything else that we are seeing out there. I just quickly wanted to pivot to the global refining macro. I'm trying to understand, as these prices are rising, Gary, if you or somebody could comment as to what you're seeing for demand out there. Are you seeing any early signs of demand destruction in your system?

Manav, this is Gary. You know, despite the fact, as you alluded to, that prices for transportation fuels are moving higher, it appears, especially domestic demand appears to be very resilient. If you look at our wholesale volumes year-over-year, we do show a reduction in sales volumes in our system. However, this isn't really a reflection of demand, but it's a result of idling the Benicia refinery, and then we exited a position in the Boston market. When we look at sales, we would say U.S. demand for gasoline is flat to slightly up. Diesel demand is up a little, and that seems to be consistent with what you're seeing in the DOEs as well, with the DOEs reflecting really increases in demand, both gasoline, diesel and jet.

Really, the big change in demand year-over-year is the pull into the export market since the conflict in Iran started. The recent DOE data shows exports from the U.S. are up 470,000 barrels a day year-over-year. The pull into the export market is causing inventory to draw in the U.S. Relative to the five-year average, total light product inventories in the U.S. have drawn 30 million barrels since January. Distillate inventory is at five-year lows. Domestic demand remains strong for diesel, with good agricultural demand as we've started planting season. The freight indices are beginning to improve a little. The export demand for distillate, especially jet, has been very strong, with interest for U.S. Gulf Coast barrels from all over the world.

As we approach driving season, gasoline inventory now at the bottom of the five-year average range. The transatlantic arb to ship to Pad 1 from Europe is closed. Both domestic and export demand remain strong. The Jones Act waiver is allowing us to supply Pad 1 and Pad 5 more efficiently from the U.S. Gulf Coast. I think as we approach driving season, VGO availability will start to become an issue. It doesn't appear there's sufficient VGO to fill both FCC and hydrocracking capacity. Current economics would favor hydrocracking, which could reduce gasoline production moving forward. I think you have read a lot about global demand destruction since the straits have been closed. It really appears to us that this isn't really demand destruction, it's more insufficient supply to meet demand.

You know, our expectations coming into the year was that new capacity additions, along with more biorenewable fuels on the market, would be sufficient to meet incremental demand. We thought supply-demand balances would be similar to last year. You'd start to see a tightening at the end of this year. The conflict in Iran has really created a market with demand significantly outpacing supply. We had very little excess refining capacity globally. It's gonna be difficult to restock inventories even once the conflict is resolved.

Perfect. You kind of alluded to it, I just wanted to confirm this. As you look into to the next at least six or nine months, you have some refiners like Valero who can run as they wish. Then there are some refiners, they may have a good kit somewhere globally, but they can't run because they don't have enough crude. I'm just trying to understand, within your refining system, sir, are you able to source any crude that you're looking for and run all out if you want to?

Yeah, Manav, this is Randy. I think the short answer is yes. I mean, most of our system is located kind of in the Mid-Continent and Gulf Coast. You know, crude availability is really not much of an issue. I think as we've seen in the stats this week, you know, the U.S. has become a major exporter of crude. It's been, you know, amplified by the SPR release. Any exports out of the U.S. have to overcome high freight and pretty steep backwardation. I mean, we're always kind of optimizing our crude slate in the Gulf Coast. You know, this time's kind of no different. Just the volatility on price and freight have been more extreme than normal.

You know, you know, with the, with the high freight costs, you know, we have made some changes in our system by, you know, cutting back waterborne crudes, running more pipeline. In addition, you know, more SPR volume that's on the market. You know, we've purchased more of that grade, just kind of optimizing against other crudes. You know, since the start of January with the Venezuela sanctions removed, you know, heavy discounts were already very advantaged for our system. You know, we were already kind of pointing our refining system to run max heavy sour crude. You know, since the Iranian event started, you know, those trends have only continued. You know, Canadian heavy crude today is trading like a $16 discount versus WTI in the Gulf. You know, the location of our system, you know, in the Gulf Coast makes it a pretty advantaged backdrop there.

Thank you, and congrats on a great quarter.

All right. Thanks, Manav.

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

Yeah, thanks so much, team, and again, really solid results. Not to focus too much on quarter-to-quarter stuff, but, you know, when you think about the second quarter indicators, they're already showing $30 on the Gulf Coast versus Q1 levels, which were $18. You know, it really hearkens back to the second quarter of 2022. At that point, your share count was kind of closer to $400 million. Today, it's closer to $300 million. Maybe this is a question for Homer, but as we start thinking about modeling out Q2 here, you know, any pluses and minuses that we should sort of be thinking about and anchoring to, and anything about March profitability that can give us a sense of what Q2 could shape up like.

Neil, I think if you look to the second quarter, definitely some headwinds and tailwinds. Certainly the steep backwardation in the crude market is a headwind. In addition to the backwardation, when you see the physical markets disconnect from the futures, it's also difficult to see. It becomes very complex to look at what that's gonna do to capture rates. In terms of tailwinds, certainly the heavy sour discounts, our system be able to maximize heavy sour crude is a tailwind. The premium regrade for jet fuel is a tailwind, as well as premiums for secondary products. A lot of pluses and minuses as we move into the second quarter.

All right, well one specific product I want to dig into is jet, Gary. I mean, there's a lot of talk about the potential for shortages in parts of the world. You know, how are you just thinking about that product in general? How you can maximize your production of it? Where are you trying to get it to? And are these concerns about jet availability globally founded or unfounded?

Yeah, to start with, I would say they are sound. Jet is incredibly short. We've been trying to maximize jet in our system. Typically, if you look at jet as a percentage of total distillates, that's a number that averages about 26% our system. In March, we got that up to over 30% jet as a percent of total distillates. In addition to that, we have a couple refineries that don't make jet today that we're moving into jet production mode to try to increase jet yields even further as we go forward.

Thanks, Gary.

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

Hey there. This quarter has highlighted the earnings volatility that refiners have faced, the range of outcomes has been wide, in part due to different commercial and financial strategies. Despite operating in the same macro environment, your results appear to have been less volatile. From your perspective, I'm curious as to what you think has enabled that. Does it reflect differences in crude sourcing, product placement or hedging strategies or something else structural in the business? Relatedly, this environment is also stress-testing the balance sheets and leverage thresholds across the sector. You've chosen to maintain a relatively elevated cash position, to Homer's earlier point in the prepared remarks. How are you thinking about that capital strategy today, particularly as a buffer against the volatility?

Yeah. Hey, Theresa, it's Homer. I mean, let me start on the risk side and hedging specifically. You know, under normal market conditions, our approach can be more formulaic, you know, and process driven, where we basically manage our exposure above or below LIFO with derivatives positions. When we started seeing higher volatility in both crude and product markets, our team met frequently, daily to review our positions, and we were just more proactive in managing our exposure. For example, we maintained our inventory positions much closer to LIFO, that reduced our overall exposure to derivatives and associated price swings, right? In addition to that also ensures that you don't have a significant draw on cash for margin calls, and you can see that we had minimal impact on that through working capital.

You know, to your second point around cash, we did move our overall base cash position towards the high end of the $4 billion-$5 billion minimum cash balance that we talked about. This is why we moved to a higher cash balance, really, after the pandemic, right? To ensure that our liquidity never, ever comes into question. While we didn't have a huge cash flow draw, hopefully this quarter highlights the value of a higher cash balance. Our cash balance, coupled with our bank facilities, we ended the quarter with almost $11 billion of total liquidity. We're really well positioned for whatever the rest of the year brings.

The last thing I'll mention is, you know, separately, we were also proactive, as I mentioned in the opening remarks, and we opportunistically pre-financed our upcoming maturities for the balance of the year. We saw an attractive window to de-risk that part of the balance sheet, and we were able to do that at a record low spread. You know, we just try to be proactive on every financial aspect of our business, whether that's risk or balance sheet or shareholder returns.

Thank you. Shifting gears, how should you think about the trajectory of DGD profitability going forward, considering current macro conditions, feedstock considerations, and regulatory changes that we've seen recently?

Yeah. This is Eric. Homer did a great job explaining. The risk management structure for DGD is a little bit different, the mark to market that we have on our forward feedstock positions will be a little bit of a headwind if we see the underlying commodities continue to rise like we did for the last month or so. That being said, the RVO is a pretty strong tailwind. We see a lot of higher margins, certainly higher in 2Q than in 1Q and overall a better 2026 versus 2025.

Thank you.

Thank you. Our next question is coming from Joe Laetsch of Morgan Stanley. Please go ahead.

Great. Thanks. Good morning. Thanks for taking my questions. As we look beyond the Middle East disruptions, can you just talk about how you see the supply-demand balance shaping up over the next couple of years? It seems like the balance was already pretty tight before the disruption, and now there is refinery damage and the need to replace inventories to contend with. Does this change how you think about mid-cycle margins going forward?

Yeah. I don't know that, you know, it'll change our approach to mid-cycle margins. You know, we take a fairly conservative approach because of our disciplined approach around capital investment. We like to take a conservative mid-cycle because we use it to justify the capital. Certainly it'll create a market that's very tight. I think even before the conflict started, our view was starting at the end of this year, global demand would outpace new refining capacity additions, and we'd have several years of tightness. That has brought that all forward, you know, with the situation that's happened. In our view, if you look at the lost total light product production that's happened since the straits have closed, you know, it takes a minimum of at least three days to rebuild stock for every day that the straits have been closed.

You know, at this stage, you know, it's at least six months to a year to start restocking inventories back to where they were. There's just not a lot of excess refining capacity out there. Then as we move forward and global demand continues to grow, it makes that situation even tighter.

Great. Thanks. That's helpful. Then on Port Arthur, I recognize you're still going through the assessment, but to the extent you can, could you just talk through the refinery damage assessment process and potential restart timeline? What are the signposts that we should be watching for from the outside here?

On March 23rd, we had a fire in the diesel hydrotreater Port Arthur. The entire refinery was shut down as a precaution. All employees were accounted for. No refinery reportable injuries as a result of the incident. The investigation into cause is ongoing. I can't share too much around that. Our operations team did an excellent job getting the smaller crude unit train back up early April, along with a coker, hydrocrackers and the reformer and distillate hydrotreater. We're currently starting up the larger crude unit as we speak, along with the FCC and Alky. We would expect by May 1st that throughput looks fairly normalized at the Port Arthur refinery. The diesel hydrotreater that experienced the fire, along with an adjacent kerosene hydrotreater do remain down, which could negatively impact capture rates some in the second quarter.

We expect to get the kerosene hydrotreater back by the third quarter. The diesel hydrotreater did sustain extensive damage. We don't have a timeline for the rebuild yet on that. As Homer mentioned, the throughput guidance, all of that is reflected in our throughput and guidance for the quarter.

Thanks. That's helpful.

Thank you. Our next question is coming from Doug Leggate of Wolfe Research. Please go ahead.

Oh, hey, everyone. I think you might have just answered part of my question there. Thanks for having me on. I'm trying to understand what's going on with physical crude impact on capture rates. If I can kind of walk through the thought process here. We saw Maya, we saw Pemex, you know, cut their K-factor in half. We're seeing Dated Brent obviously at big premiums. Now apparently a flotilla of tankers coming to the U.S. Gulf Coast, perhaps putting a bid under WTI. I'm just curious, when you look at your slate, how is the physical side of the crude market impacting the capture rate? If I may, my follow-up is specifically for Homer.

You've got Homer, you've got probably one of the best balance sheets, if not the best balance sheet in the sector, which means you don't have a lot of options for your surplus cash. My question is that your valuation today, if you sort of look at the implied free cash flow forever, not the windfall you have now, is north of $7 billion at a 10% discount rate. How do you think about your valuation in the context of what you do with that cash as it relates specifically to share buybacks?

Doug, I'll start on the crude side. I mean, for the most part, as Gary mentioned before, you know, part of the headwind on capture is on the backwardation that is in the market. You know, the steep backwardation. I mean, it hit some high last month at $11-$14. It's into the $6 range now, and, you know, it has moved higher over the last couple days. You know, as a look kind of in the capture, I mean, some of the grades are already included in the capture calculation. It's already reflecting some of that movement in the capture calculation. Outside of that, I mean, there's things that we're doing that's not captured in it. It's, you know, Venezuelan purchases.

You know, since the January sanctions removal, we've meaningful ramped up Venezuela runs in our systems. All that done at better economics in our alternative and heavy tower. As we touched on before, the heavy grades in the Gulf Coast continue to look very attractive for our system.

Doug, hey, this is Homer. Thanks for comment on the balance sheet. You know, I think your comment on annuitizing current margins, there's no doubt current margins are good. As you can tell by our results, we put ourselves in a really good position to take advantage of that, right? We're not hanging our strategy on just the current margin environment. Obviously, we continue to optimize and grow the business, but we're doing that with discipline around minimal return thresholds, and we're using a longer mid-cycle price set, as Gary highlighted earlier. We also continue to work hard to manage our costs, and all this puts us in a great position for shareholder returns.

With respect to buybacks, I think you have to start by understanding that share repurchases are really an efficient and flexible means of returning excess cash to shareholders in the broader context of capital allocation, right? When you look at other uses of cash in our balance sheet, and as you touched on our balance sheet and cash position are in the best position that they've been for a very, very long time.

You know, what we will do is, you know, our underlying commitments around balance sheet, minimum cash, and shareholder returns will not change, but we may move within the bounds we've laid out depending on the environment that we're in. We clearly did that with respect to cash during the first quarter. You know, outside of that, our net debt to cap is still below our long-term range, 20%-30%, right? We've got plenty of coverage of other uses of cash. I think you'll continue to see us return accessory cash flow to shareholders through share repurchases. You know, this approach has reduced our overall share count by 42% since 2014. For what it's worth, Doug, our return on buyback is close to 20% over that time period.

buybacks do create perpetual value by reducing the share count. I think you should expect us to continue to operate in that mode.

Yeah. A lot of downturns gave you that opportunity in the last 10 years, Homer, for sure. Thanks so much, guys. I appreciate it.

Thanks, Doug.

Thank you. Our next question is coming from Phillip Jungwirth of BMO Capital Markets. Please go ahead.

Thanks. Good morning. You mentioned earlier making some adjustments in the Gulf Coast on the feedstock sourcing side, and was just wondering if you could talk about any changes you've made specific to the North Atlantic region. You've Dated Brent in the indicator, but I assume you can do a bit better here, especially at Québec City. Maybe also just touch on the export side too, and how you're optimizing given market volatility and global demand for products.

Sure, Phillip, this is Randy. You know, for Québec, I mean, it's mostly 100% North America crude slate. It, you know, it's taking barrels from Western Canada and from the Gulf Coast that, you know, tend to avoid some of the spikes that we saw in Dated Brent earlier in the month. For Pembroke, I mean, obviously we do have some volatility that we saw in the prompt dated that seems to have lined out, you know, as some of the initial panic buying that was happening in the market. It even got to the point where, you know, some people were reportedly cutting runs as dated spiked higher.

You know, fortunately, we've kind of avoided some of the peak numbers on some of the crude purchases. You know, looking ahead, it looks like, you know, our margin environment for Pembroke still looks favorable as we, as we move forward.

Okay, great. One of the questions we regularly get is around some form of restriction on product exports. Just based on your conversations, where would you put the level of government support here? What would be any unintended consequences? What other levers are there to pull to ease some of the upward pressure on gasoline prices, whether it's RVP or other things that could be done?

This is Rich Walsh. There's been lots of conversations with the administration, and they're, you know, keenly aware of, you know, what they, you know, watching the prices out there, and they've already taken actions. You know, they gave a Jones Act waiver real early on. That really helped out. You know, the reality is, you know, any kind of export ban actually just makes the situation way worse, and they're keenly aware of that already. You know, the U.S. is, you know, long crude and long refining production, you know, we are tethered to the world market.

It's important, you know, to make sure that we get optimized and provide, and this is a huge competitive advantage for the U.S. as well. I think the administration fully understands that. They're looking at all the options and tools that are out there, but we're not positioned like some other countries where they just don't have the resources that we have. I don't think those kinds of strategies really make sense for us. I think the administration's well aware of that, and I don't think there's any real meaningful potential for that to happen.

Thank you.

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

Hey, thanks for taking my questions. The first conflict at all, and really two conflicts that have resulted in pretty massive dislocations in the market, change your way you think about investment opportunities and how you run the business in the medium-term. I know, for example, you talked about a potential VGO shortage in the country. If that's an area that you could figure out some investment in to help close your own shortage or other opportunities such as that.

Hey, Jason, it's Lane. You know, I think it is a good point. How I think about it, and of course, we think about it, is the Ukrainian-Iran conflict has really demonstrated, I would say, the resilience of North America. Largely due to the fact that we have such a robust and oil and gas industry has really helped position us for the two conflicts that have occurred. Of course, we sit here in the Gulf Coast. We have the most flexibility on crude feedstocks. We can export anywhere in the world. In terms of how we sort of think about our projects, we like to bucket them, right? The way I'm gonna characterize is we like projects that increase our commercial leverage.

If you think about your VGO question, that's a position that we wanna get through our gating system to maybe position ourselves not to be so lenient or so dependent upon VGO imports. It doesn't mean we're gonna lose our discipline, but it means that we see that there's an issue that has been really pointed out with respect to these projects, this issue, the conflicts. We also obviously like reliability projects. You know, the key to this is to be able to run through all these. You know, be able to move your assets around and run reliably through it. Finally, yields.

Better yields, which is essentially the FCC project. When we can upgrade to what we're making, we like that. Ethanol, which isn't obviously, you wouldn't think of it as being directly tied to this, but what you are seeing in the world is people are looking at, Hey, can I blend more ethanol in the fuel mix? So we have a positive view of the ethanol business, so we have been investing in ethanol. Same thing, some incremental growth and how much we make, yield improvements to increase the amount of ethanol. Again, there's this backdrop of improving carbon intensity. The renewable diesel, I don't know that it's so much dependent on what we've seen in the world, but obviously we have the SAF project hanging out there. We just wanna see policy.

Everything that happens in that space is very dependent on how policy works out and how it can sort of survive from administration to administration.

Great. That's a really helpful framework. Thanks. My follow-up is just on the futures curves and specifically on futures cracks. You know, I think the market broadly uses that to help price the refining stocks. The reality is, based on conversations we've had, it seems like there's not so much liquidity on the back end of those curves. Thinking about your comment that it could take six to 12 months if Hormuz was open today for inventories to. How do you think about where cracks are on futures in the second half of the year? Do you think we see a similar dynamic as during the Russo-Ukrainian War, where, you know, cracks kind of in the back end trend higher through the year and end up higher than what was represented early in the year? Just any color around futures cracks would be helpful. Thanks.

That is our view, is we think the back end of the curve is undervalued. I think, you know, a lot of it is it's somewhat hindering trade flows that need to happen. The high freight rates along with steep backwardation are making markets that are really short and need product today, looking to the future and thinking they're going to be able to buy that product at lower values in the future. In reality, you know, the curve just rolling up, and we expect that to continue.

Great. Thanks for the answers.

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

Hey, thanks, and good morning. You mentioned some of your commercial opportunities in areas like the North Atlantic. Do you also have opportunities on the West Coast? I guess in particular, are you using Jones Act waivers to ship both crude and products to the West Coast?

Hey, Matthew, this is Randy. I'll touch on that. I mean, we have issued several Jones Act waivers, primarily for products, both renewables and conventional products, moving both from the Gulf Coast to the West Coast and to Florida.

Sounds good. The ethanol results seem pretty good, but better than our expectations. Was that just a function of improving values on the co-products, or were you able to record any 45Z contributions in the ethanol segment? I guess, what's the overall outlook for 45Z and the potential contribution this year in ethanol? Thank you.

Yeah, this is Eric. You know, Lane alluded to what we're seeing in ethanol demand globally. As one of the largest exporters of ethanol, you're seeing a pull on ethanol. The underlying value is really as the hydrocarbon prices have increased, so has the value of octane. Ethanol being an octane component, has now become the cheapest form of octane in the world. That is why you're seeing a lot of interest, and you can use ethanol as a supplement, you know, just like as in the U.S. You see a lot of countries going from E0 to E10. Brazil is going from E30 to E32. India's going to E20 and talking about going higher than that. Everyone sees that ethanol is a cheaper form of liquid fuel.

You're seeing demand in ethanol. As far as PTC, what we booked in the first quarter was $0.10 a gallon on 10 of our plants using the original definition of qualified sales. What we'll ultimately see once the guidance is published, which hopefully is the end of this year, but it may not be till next year, is you'll get the next $0.10-$0.20 across all our plants, across all our sales.

Great. Thank you.

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

Morning, all. Can you hear me?

Good morning, Paul.

Hello?

Hey, Paul.

Can you hear me?

Yeah, we can hear you.

Hi, can you hear me, guys?

Yep, we can hear you.

Sorry, I got, like, a $15 phone here. Thanks for everything. You had mentioned the shortage of VGO, and I just wondered if you could talk a little bit about where you might anticipate other shortages, actual physical shortages emerging in the oil chain. That's sort of question number one. Thanks.

[inaudible]

I don't know of any, but yeah, obviously VGO is an issue, this is Lane. I mean, we... If you think about how trade flow worked before all this started, net VGO flowed from essentially Europe and the Middle East into the U.S. to sort of satisfy the complexity, the FCCs and the hydrocrackers here. I don't know that we see a, you know, like... Besides the jet, where it's just everybody knows about jet. We're talking about all these other intermediates. I don't know that, at least in the United States, we see any other sort of structural issues in terms of intermediates.

Okay, that's great. Secondly, Lane, you've talked about in the past, I remember Joe certainly saying this, that when you look at your inventories over time, you kind of don't play inventories. It's almost more that you're just, you know, working operationally to optimize your performance. I had a question. Firstly, I assume that you're still doing that. Secondly, how do you see a situation where inventories deplete? I assume that the industry won't go to zero inventories, right? I was thinking, as we get these draws, when is the point at which, I guess, prices go a ton higher, is the best guess? Thanks.

Hey, Paul. I'll take the first thing. The answer is yes. I mean, I think it was, Homer earlier alluded to the fact we, you know, we could see all this volatility in the commodity market. We're keenly aware that, you know, the tendency would be for us is, you know, say you have a refinery incident, and crude oil inventories start creeping up above what we would consider to be our working inventories. We can get into where it puts us short paper. We worked very hard just to avoid the derivative volatility and worked hard to make sure that we are operating around our working inventory, which equals our LIFO inventories. In terms of the latter part of that question.

Yeah, it's very difficult for us to tell. I do think, as I alluded to before, with the steep backwardation that you see in the market, a lot of markets that are short product today are basically trying to live hand-to-mouth, thinking that they'll be able to buy replacement barrels in the future at cheaper values. At some point in time, they'll realize that they need the volume. I think you'll see a reaction in price. At what inventory level that occurs, I don't really have any insight.

Yeah, I understand. It's a tough one. Thanks a lot.

Okay. Thanks, Paul.

Thank you. At this time, I would like to turn the floor back over to Mr. Donovan for closing comments.

All right. Well, we appreciate everyone joining us today for the call. As always, feel free to contact our investor relations team if you have any additional questions. Have a great day.

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