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DATE

Thursday, April 30, 2026 at 10 a.m. ET

CALL PARTICIPANTS

  • Chairman, CEO, and President — Lane Riggs
  • Executive Vice President and COO — Gary Simmons
  • Senior Vice President and CFO — Homer Bhullar
  • Executive Vice President and General Counsel — Rich Walsh
  • Vice President, Investor Relations — Brian Donovan
  • Senior Vice President, North American Fuels — Randy [full last name not given]
  • Vice President, Alternative Fuels — Eric Fisher

TAKEAWAYS

  • Net Income -- $1.3 billion, or $4.22 per share, reversing a net loss of $595 million ($1.90 per share) in the prior-year period.
  • Refining Segment Operating Income -- $1.8 billion, compared to a prior-year operating loss of $530 million; adjusted operating income for the prior year was $605 million.
  • Refining Throughput Volumes -- 2.9 million barrels per day, with cash operating expenses of $5.13 per barrel.
  • Renewable Diesel Segment Operating Income -- $139 million, compared to a segment loss of $141 million in the prior year; sales volumes averaged 3 million gallons per day.
  • Ethanol Segment Operating Income -- $90 million, up from $20 million in the prior year; production volumes averaged 4.6 million gallons per day.
  • Shareholder Cash Returns -- $938 million, representing a payout ratio of 59% for the quarter.
  • Dividend -- Quarterly cash dividend raised by 6% on January 22.
  • Debt Issuance -- $850 million of ten-year notes issued in March at a 5.15% coupon; notes priced at a sector record-low 102 basis points above treasuries.
  • Cash and Liquidity -- $5.7 billion in cash and equivalents at quarter end, targeting the high end of the $4 billion to $5 billion cash range for greater flexibility.
  • Net Debt to Capitalization -- 18%, net of cash and equivalents as of March 31, 2026.
  • Capital Investments -- $448 million invested, of which $404 million was for sustaining activities and $430 million attributable directly to Valero.
  • 2026 General and Administrative Expenses Outlook -- Approximately $960 million.
  • St. Charles Refinery Project -- $230 million investment for unit optimization, expected to come online in 2026 to expand high-value product production.
  • Port Arthur Fire Impact -- Incident in late March resulted in refinery shutdown; smaller crude unit and key process units restarted, but diesel hydrotreater remains out of service, with incremental capital expenditures anticipated for repairs.
  • Benicia Refinery Transition -- Ceasing refining operations leads to $100 million of incremental depreciation in Q1; $33 million more expected in Q2, affecting earnings by an estimated $0.09 per share.
  • Q2 2026 Refining Throughput Guidance -- Gulf Coast: 1.69-1.74 million barrels/day; Mid-Continent: 450,000-470,000; West Coast: 120,000-130,000; North Atlantic: 480,000-500,000 barrels/day.
  • Q2 2026 Segment Outlook -- Refining cash operating expenses expected at $4.85 per barrel; Renewable Diesel sales at 320 million gallons, with $0.46 per gallon operating expenses; Ethanol production at 4.7 million gallons/day, with $0.39 per gallon operating expenses.
  • Balance Sheet Strength -- Nearly $11 billion in total liquidity at quarter end, combining cash balances and bank facilities.

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RISKS

  • Port Arthur fire caused an unplanned refinery shutdown, with ongoing repairs and uncertainty around the diesel hydrotreater timeline, negatively impacting capture rates and throughput in the near term.
  • Ceasing Benicia refinery operations resulted in material incremental depreciation and will continue to affect earnings until assets are fully idled.
  • Management highlighted "Steep backwardation in the crude market" and "disconnect from the futures," as headwinds that may compress capture rates in the next quarter.
  • The Renewable Diesel segment may face a "headwind if we see the underlying commodities continue to rise like we did for the last month or so," according to Eric Fisher.

SUMMARY

Valero Energy Corporation (VLO 0.28%) delivered a marked turnaround in profitability, supported by segment-wide performance gains, capably navigating commodity market disruption and supply shocks. Management confirmed an opportunistic $850 million debt refinancing at favorable terms, bolstering liquidity in anticipation of ongoing volatility. The company reiterated disciplined capital allocation, underscored by a 6% dividend increase and sustained share repurchases, alongside targeted investments such as the $230 million St. Charles upgrade. Strategic operational flexing was evident as refining throughput guidance for key regions explicitly reflects plant-specific events, including Port Arthur’s post-fire status and Benicia's phased exit from refining. Near-term risks remain centered on outage recovery and sustained market backwardation on both the crude and product sides.

  • Management stressed that "domestic demand appears to be very resilient," clarifying that observed volume reductions were attributable to the Benicia idling and Boston market exit, not diminished end-user demand.
  • The company raised jet fuel yield to over 30% of total distillates in March, a record, and is accelerating conversion of additional refineries to jet production in response to global shortages.
  • Export demand for distillates rose strongly, with DOE data showing U.S. exports up 470,000 barrels per day year over year since the conflict in Iran began.
  • Management stated, "The pull into the export market is causing inventory to draw in the U.S," resulting in light product inventories falling by 30 million barrels since January, and distillate inventories at five-year lows.
  • Valero confirmed strategic crude slate optimization—citing increased purchases of SPR and discounted Venezuelan crude—with Canadian heavy crude at a $16 Gulf Coast discount to WTI.
  • The Rich Walsh communicated confidence in U.S. administration awareness of export market dynamics, asserting, "I do not think there is meaningful potential for an export ban to happen."
  • Ethanol segment results benefited from global pull and higher octane values, with $0.10 per gallon in 45Z (PTC) credits booked at 10 plants in Q1; further guidance is pending regulatory clarification.
  • Risk management efforts intensified with "inventory positions much closer to LIFO" and daily hedging reviews, insulating the company from wider derivative-driven volatility.
  • On the outlook for segmental margins, management anticipated that "the back end of the curve is undervalued," projecting that future price realization may surpass current market signals if supply constraints persist.
  • Valero highlighted an ongoing focus on shorter-cycle optimization and feedstock flexibility projects—especially to reduce VGO dependency—while reiterating investment discipline calibrated to "conservative mid-cycle."

INDUSTRY GLOSSARY

  • VGO (Vacuum Gas Oil): A heavy oil distillation cut used as a feedstock for fluid catalytic cracking and hydrocracking in refineries.
  • FCC (Fluid Catalytic Cracking): A refining process that converts heavy hydrocarbons into lighter products like gasoline and propylene.
  • LIFO (Last-In, First-Out): An accounting method for inventory in which the most recently acquired items are assumed to be sold first.
  • DGD (Diamond Green Diesel): A renewable diesel production joint venture between Valero and another partner, not fully consolidated in all Valero segment results.
  • RVO (Renewable Volume Obligation): A regulatory compliance requirement under U.S. renewable fuel standards mandating certain biofuel volumes in the transportation fuel mix.
  • PTC (45Z): A production tax credit for low-carbon biofuels, referenced here as a per-gallon incentive for ethanol plants.
  • SPR (Strategic Petroleum Reserve): The U.S. government’s emergency crude oil stockpile, released to manage supply or market disruptions.
  • Jones Act Waiver: A temporary exemption allowing non-U.S. vessels to transport goods between U.S. ports, often granted during supply emergencies to ease logistics constraints.

Full Conference Call Transcript

Operator: Greetings, and welcome to Valero Energy Corporation First Quarter 2026 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone requires operator assistance during the conference, 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.

Brian Donovan: Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2026 Earnings Conference Call. I am 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 would 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 will now turn the call over to Lane for opening remarks.

Lane Riggs: Thank you, Brian, and good morning, everyone. I am pleased to report that it was 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 Venezuela 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 and delivering a record monthly jet yield.

At the same time, our commercial and financial teams proactively managed commodity risk to mitigate unique 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 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 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 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. Consistent execution across these priorities positions us to benefit from the current margin environment and will continue to differentiate Valero. With that, I will turn the call over to Homer.

Homer Bhullar: Thank you, Lane. For the first quarter 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 $1.9 per share for the first quarter 2025. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders for the first quarter 2025 was $282 million or $0.89 per share. The Refining segment reported $1.8 billion of operating income for the first quarter 2026, compared to an operating loss of $530 million for the first quarter 2025. Adjusted operating income for the first quarter 2025 was $605 million. Refining throughput volumes in the first quarter 2026 averaged 2.9 million barrels per day.

Refining cash operating expenses were $5.13 per barrel in the first quarter 2026. The Renewable Diesel segment reported operating income of $139 million for the first quarter 2026, compared to an operating loss of $141 million for the first quarter 2025. Renewable Diesel segment sales volumes averaged 3 million gallons per day in the first quarter 2026. The Ethanol segment reported $90 million of operating income for the first quarter 2026, compared to $20 million for the first quarter 2025. Ethanol production volumes averaged 4.6 million gallons per day in the first quarter 2026. G&A expenses were $285 million for the first quarter 2026.

Depreciation and amortization expense was $840 million for the first quarter 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 2026. The effective tax rate was 23%. Net cash provided by operating activities was $1.4 billion in the first quarter 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’s share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.6 billion in the first quarter 2026.

Regarding investing activities, we made $448 million of capital investments in the first quarter 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’s share of DGD and other variable interest entities, capital investments attributable to Valero were $430 million in the first quarter 2026. Moving to financing activities, we remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $938 million in the first quarter 2026, resulting in a payout ratio of 59% for the quarter.

And on January 22, 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 ten-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 ten-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 03/31/2026.

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 to $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 will 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, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.69 million to 1.74 million barrels per day, reflecting reduced rates at Port Arthur; Mid-Continent at 450,000 to 470,000 barrels per day; West Coast at 120,000 to 130,000 barrels per day, reflecting the idling of Benicia; and North Atlantic at 480,000 to 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. 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.

Operator: We will now open the call for questions. The floor is now open for questions. Today’s first question is coming from Manav Gupta of UBS. Please go ahead.

Manav Gupta: 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, and I am trying to understand, as these prices are rising, what you are seeing for demand out there. Are you seeing any early signs of demand destruction in your system? You kind of alluded to it, so I just want to confirm this. As you look into the next at least six or nine months, you have some refiners like Valero who can run as they wish, and then there are some refiners who may have a good kit somewhere globally but they cannot run because they do not have enough crude.

I am just trying to understand within your refining system, are you able to source any crude that you are looking for and run all out if you want to?

Gary Simmons: Yes, Manav, this is Gary. Despite the fact that, as you alluded to, prices for transportation fuels are moving higher, 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 is not really a reflection of demand, but a result of idling the Benicia refinery and exiting 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.

That seems to be consistent with what you are seeing in the DOE data as well, with the DOEs reflecting increases in demand for gasoline, diesel, and jet. 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 show 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 inventories are at five-year lows.

Domestic demand remains strong for diesel with good agricultural demand as we start planting season, and the freight indices are beginning to improve a little. 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 is now at the bottom of the five-year average range. The trans-Atlantic arb to ship to PADD 1 from Europe is closed. Both domestic and export demand remain strong. The Jones Act waiver is allowing us to supply PADD 1 and PADD 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 does not appear there is sufficient VGO to fill both FCC and hydrocracking capacity. Current economics would favor hydrocracking, which could reduce gasoline production moving forward. You have read a lot about global demand destruction since the straits have been closed. It really appears to us that this is not demand destruction; this is insufficient supply to meet demand. Our expectations coming into the year were that new capacity additions along with more bio-renewable fuels on the market would be sufficient to meet incremental demand. We thought supply-demand balances would be similar to last year and then you would start to see a tightening at the end of this year.

But the conflict in Iran has really created a market with demand significantly outpacing supply. We had very little excess refining capacity globally, so it is going to be difficult to restock inventories even once the conflict is resolved.

Randy: Manav, this is Randy. I think the short answer to your crude sourcing question is yes. Most of our system is located in the Mid-Continent and Gulf Coast, so crude availability is really not much of an issue. As we have seen in the stats this week, the U.S. has become a major exporter of crude, amplified by the SPR release. Any exports out of the U.S. have to overcome high freight and pretty steep backwardation. We are always optimizing our crude slate in the Gulf Coast, and this time is no different, just the volatility on price and freight have been more extreme than normal.

With the high freight costs, we have made some changes in our system by cutting back waterborne crudes and running more pipeline barrels. In addition, with more SPR volume on the market, we have purchased more of that grade, optimizing against other crudes. Since January, with the Venezuela sanctions removed, heavy discounts were already very advantaged for our system, and since the Iranian event started, those trends have only continued. Canadian heavy crude today is trading at about a $16 discount versus WTI in the Gulf. The location of our system in the Gulf Coast makes it a very advantaged backdrop.

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

Neil Mehta: Thanks so much, team, and again really solid results. Not to focus too much on quarter-to-quarter stuff, but when you think about the second quarter indicators, they are already showing $30 on the Gulf Coast versus Q1 levels, which were $18. It harkens back to 2022 when at that point your share count was closer to 400 million. Today, it is closer to 300 million. Maybe that is a question for Homer. As we start thinking about modeling out Q2, any pluses and minuses that we should be thinking about and anchoring to? Anything about March profitability that can give us a sense of what Q2 could shape up like?

And then one specific product to dig into is jet, Gary. There is a lot of talk about the potential for shortages in parts of the world. How are you thinking about that product in general, how you can maximize your production of it, where you are trying to get it to, and are these concerns about jet availability globally founded or unfounded?

Homer Bhullar: Yes, Neil, I think if you look to the second quarter, definitely some headwinds and tailwinds. 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 becomes very complex to see what that will do to capture rates. In terms of tailwinds, heavy sour discounts and our system’s ability to maximize heavy sour crude are tailwinds. The premium regrade for jet fuel is a tailwind, as well as premiums for secondary products. So there are a lot of pluses and minuses as we move into the second quarter.

Gary Simmons: On jet, I would say the concerns are founded. Jet is incredibly short. We have been trying to maximize jet in our system. Typically, if you look at jet as a percentage of total distillate, that averages 26% in our system. In March, we got that up to over 30%—jet as a percent of total distillates. In addition, we have a couple of refineries that do not make jet today that we are moving into jet production mode to try to increase jet yields even further as we go forward.

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

Theresa Chen: This quarter has highlighted the earnings volatility that refiners faced, and 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, what 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 chose 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?

And shifting gears, how should we think about the trajectory of DGD profitability going forward, considering current macro conditions, feedstock considerations, and regulatory changes that we have seen recently?

Homer Bhullar: Hey, Theresa, I will start on the risk side and hedging specifically. Under normal market conditions, our approach can be more formulaic and process-driven where we basically manage our exposure above or below LIFO with derivatives positions. But when we started seeing higher volatility in both crude and product markets, our team met frequently—daily—to review our positions, and we were more proactive in managing our exposure. For example, we maintained our inventory positions much closer to LIFO. That reduced our overall exposure to derivatives-associated price swings, and in addition, it helps ensure you do not have a significant draw on cash for margin calls. You can see that we had minimal impact on that through working capital.

On cash, we did move our overall base cash position towards the high end of the $4 billion to $5 billion minimum cash balance we have talked about. This is why we moved to a higher cash balance after the pandemic—to ensure that our liquidity never comes into question. While we did not 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 left us with almost $11 billion of total liquidity at quarter end, so we are really well positioned for whatever the rest of the year brings.

Lastly, 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 at a record-low spread. We just try to be proactive on every financial aspect of our business—risk, balance sheet, and shareholder returns.

Eric Fisher: On DGD, Homer did a great job explaining the risk management structure. It is a little bit different, and so 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 said, the RVO is a pretty strong tailwind. We see higher margins—certainly higher in Q2 than in Q1—and overall, a better 2026 versus 2025.

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

Joe Lache: Great, thanks. Good morning, and thanks for taking my questions. As we look beyond the Middle East disruptions, can you 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?

And on Port Arthur, I recognize you are still going through the assessments, but to the extent you can, could you talk through the refinery damage assessment process and potential restart timeline, and what are the signposts that we should be watching for from the outside here?

Lane Riggs: I do not know that this changes our approach to mid-cycle margins. 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. But certainly, it will create a market that is very tight. Even before the conflict started, our view was that starting at the end of this year, global demand would outpace new refining capacity additions, and we would have several years of tightness. The situation has brought that forward.

In our view, if you look at the lost total light product production that has happened since the straits have closed, it takes a minimum of at least three days to rebuild stock for every day that the straits have been closed. At this stage, it is at least six months to a year to start restocking inventories back to where they were. There is just not a lot of excess refining capacity out there, and as we move forward and global demand continues to grow, it makes that situation even tighter.

Gary Simmons: On Port Arthur, on March 23 we had a fire in the diesel hydrotreater at Port Arthur, and the entire refinery was shut down as a precaution. All employees were accounted for. No refinery injuries were reported as a result of the incident. The investigation into the cause is ongoing, so I cannot share too much around that. Our operations team did an excellent job getting the smaller crude unit train back up in early April, along with the coker, hydrocrackers, the reformer, and a distillate hydrotreater. We are currently starting up the larger crude unit as we speak, along with the FCC and alkylation unit.

We would expect by May 1 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 do not have a timeline for the rebuild yet. As Homer mentioned, the impact is reflected in our throughput guidance for the quarter.

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

Doug Leggate: Thanks for having me on. I am trying to understand what is going on with the physical crude impact on capture rates. We saw Maya, we saw Pemex cut their K factor in half. We are seeing Dated Brent at big premiums, and now apparently a flotilla of tankers coming to the U.S. Gulf Coast perhaps putting a bid under WTI. When you look at your slate, how is the physical side of the crude market impacting the capture rate? And for Homer, you have one of the best balance sheets in the sector, which means you have a lot of options for your surplus cash.

If you look at the implied free cash flow forever—excluding the current windfall—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, specifically as it relates to share buybacks?

Randy: I will start on the crude side. For the most part, Gary mentioned before, part of the headwind on capture is the steep backwardation in the market. It hit some highs last month at $11 to $14; it is in the $6 range now, and it has moved higher over the last couple of days. Some of the grades are already included in the capture calculation, so that is already reflecting some of the movement. Outside of that, there are things that we are doing that are not captured in it—Venezuelan purchases, for example. Since the January sanctions removal, we have meaningfully ramped up Venezuela runs in our system, all done at better economics than our alternatives on heavy sour.

As we touched on before, heavy grades in the Gulf Coast continue to look very attractive for our system.

Homer Bhullar: Doug, thanks for your comment on the balance sheet. There is no doubt current margins are good, but as you can tell by our results, we put ourselves in a really good position to take advantage of that and not hang our strategy on just the current margin environment. We continue to optimize and grow the business with discipline around minimum return thresholds, and we are using a longer mid-cycle price set, as Lane highlighted earlier. We also continue to work hard to manage our costs, and all of this puts us in a great position for shareholder returns.

With respect to buybacks, share repurchases are an efficient and flexible means of returning excess cash to shareholders in the broader context of capital allocation. Our balance sheet and cash position are in the best position they have been for a very long time. Our underlying commitments around the balance sheet, minimum cash, and shareholder returns will not change, but we may move within the bounds we have laid out depending on the environment. We clearly did that with respect to cash during the first quarter. Our net debt to cap is still below our long-term range of 20% to 30%, and we have plenty of coverage for other uses of cash.

I think you will continue to see us return excess free cash flow to shareholders through share repurchases. This approach has reduced our overall share count by 42% since 2014, and our return on buybacks is close to 20% over that time period. Buybacks do create perpetual value by reducing the share count, so you should expect us to continue to operate in that mode.

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

Philip Jungwirth: You mentioned earlier making some adjustments in the Gulf Coast on the feedstock sourcing side, and I was wondering if you could talk about any changes you have made specific to the North Atlantic region. You have Dated Brent in the indicator, but I assume you can do a bit better here, especially at Quebec City. Maybe also touch on the export side and how you are optimizing given market volatility and global demand for products? And we regularly get questions around some form of restriction on product exports. 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 RVP or other things that could be done?

Randy: Sure, Phil. For Quebec, it is mostly a 100% North American crude slate—taking barrels from Western Canada and from the Gulf Coast—that tends to avoid some of the spikes we saw in Dated Brent earlier in the month. For Pembroke, we did see volatility in the prompt-dated market that seems to have lined out as some of the initial panic buying subsided. It even got to the point where some people were reportedly cutting runs as Dated Brent spiked higher. Fortunately, we avoided some of the peak numbers on crude purchases. Looking ahead, our margin environment for Pembroke still looks favorable as we move forward.

Rich Walsh: On export restrictions, there have been lots of conversations with the administration, and they are keenly aware and watching prices. They have already taken actions—the Jones Act waiver early on really helped. The reality is any kind of export ban actually makes the situation worse, and they are keenly aware of that. The U.S. is long crude and long refining production, and we are tethered to the world market. It is important to make sure that we get optimized and provide supply to global markets—this is a huge competitive advantage for the U.S. The administration fully understands that.

They are looking at all the options and tools out there, but we are not positioned like some other countries that do not have the resources we have. Those kinds of strategies really do not make sense for us. I do not think there is meaningful potential for an export ban to happen.

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

Jason Gabelman: Thanks for taking my questions. The recent conflicts have resulted in pretty massive dislocations in the market. Do they change the way you think about investment opportunities and how you run the business in the medium term? For example, you talked about a potential VGO shortage in the country—could that be an area for investment to help close your own shortage, or are there other opportunities like that? And on futures curves and specifically futures cracks, the market broadly uses that to help price refining stocks, but there is not much liquidity on the back end of those curves.

If it could take six to twelve months if Hormuz was open today to rebuild inventories, 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 Russia-Ukraine war where the back end trends higher through the year and ends up higher than what was represented early in the year?

Lane Riggs: It is a good point. The Ukraine and Iran conflicts have really demonstrated the resilience of North America, largely due to a robust oil and gas industry. We sit in the Gulf Coast; we have the most flexibility on crude feedstocks, and we can export anywhere in the world. In terms of how we think about projects, we like to bucket them. We like projects that increase our commercial leverage. On your VGO question, that is an area we want to get through our gating system to position ourselves to be less dependent on VGO imports. We are not going to lose our discipline, but we see an issue highlighted by these conflicts.

We also like reliability projects—the key is to be able to move your assets around and run reliably through all this. Finally, yield projects—better yields, essentially FCC projects, to upgrade what we are making. On ethanol, while it is not directly tied to the conflicts, you are seeing the world looking to blend more ethanol in the fuel mix. We have a positive view of the ethanol business and are investing in incremental growth and yield improvements, with the backdrop of improving carbon intensity. In renewable diesel, we have the SAP project hanging out there; we want to see policy. Everything in that space is very dependent on how policy works out across administrations.

Gary Simmons: On the futures curves, our view is the back end of the curve is undervalued. It is somewhat hindering trade flows that need to happen. High freight rates along with steep backwardation are making markets that are short and need product today look to the future thinking they will be able to buy that product at lower values. In reality, it is the curve just rolling up, and we expect that to continue.

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

Matthew Blair: 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 and, in particular, are you using Jones Act waivers to ship both crude and products to the West Coast? And the ethanol results seemed pretty good—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? What is the overall outlook for 45Z and the potential contribution this year in ethanol?

Randy: Matthew, we have utilized several Jones Act waivers, primarily for products—both renewables and conventional products—moving from the Gulf Coast to the West Coast and to Florida.

Eric Fisher: On ethanol, Lane alluded to what we are seeing in global demand. As one of the largest exporters of ethanol, we are seeing a pull on ethanol. As hydrocarbon prices have increased, so has the value of octane, and ethanol—being an octane component—has become the cheapest form of octane in the world. That is why you are seeing a lot of interest, and countries can use ethanol as a supplement just like in the U.S. You see a lot of countries going from E0 to E10. Brazil is going from E30 to E32. India is going to E20 and talking about going higher. Everyone sees ethanol as a cheaper form of liquid fuel, so you are seeing demand.

As far as the PTC (45Z), 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 will ultimately see once the guidance is published—hopefully by the end of this year, but it may not be until next year—is the next $0.10 to $0.20 across all our plants, across all our sales.

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

Paul Sankey: Good morning. You had mentioned the shortage of VGO, and I wondered if you could talk a little bit about where you might anticipate other actual physical shortages emerging in the oil chain. Secondly, Lane, you have talked in the past—Joe certainly has said this—that when you look at your inventories over time, you do not play inventories; you are working operationally to optimize your performance. Firstly, I assume that you are still doing that. Secondly, how do you see a situation where inventories deplete? I assume that the industry will not go to zero inventories. As we get these draws, when is the point at which prices go a ton higher, in your best guess?

Lane Riggs: On other shortages, obviously VGO is an issue. If you think about how trade flows worked before all this started, net VGO flowed from Europe and the Middle East into the U.S. to satisfy the complexity—the FCCs and the hydrocrackers—here. Besides jet, which everybody knows about, in the U.S. we do not see other structural issues in terms of intermediates at this point. On inventories, yes, we continue to operate around our working inventory, which equals our LIFO inventories. Homer alluded to the volatility in the commodity market; we worked hard to avoid derivative volatility and to keep crude oil inventories from creeping above working levels that would create a short paper position.

Gary Simmons: It is very difficult to tell at what inventory level prices inflect sharply higher. As I alluded to before, with steep backwardation, a lot of markets that are short product today are living hand-to-mouth, thinking they will be able to buy replacement barrels in the future at cheaper values. At some point, they will realize they need the volume, and you will see a reaction in price. At what inventory level that occurs, I do not have any specific insight.

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

Brian Donovan: 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.

Operator: Ladies and gentlemen, thank you for your participation. This concludes today’s event. You may disconnect your lines or log off the webcast at this time and enjoy the rest of your day.