Valero Energy (VLO) Q3 2025 Earnings Call Transcript

Image source: The Motley Fool.

DATE

Thursday, Oct. 23, 2025, at 10 a.m. ET

CALL PARTICIPANTS

• Chairman, Chief Executive Officer, and President — Lane Riggs
• Executive Vice President and Chief Financial Officer — Jason Fraser
• Executive Vice President and Chief Operating Officer — Gary Simmons
• Executive Vice President and General Counsel — Rich Walsh
• Vice President, Investor Relations and Finance — Homer Bhullar
• Executive Vice President, Alternative Fuels — Eric Fisher
• Senior Vice President, Refining Operations — Greg Bram

Need a quote from a Motley Fool analyst? Email pr@fool.com

RISKS

• The renewable diesel segment incurred a $28 million operating loss in Q3 2025 due to unfavorable economics, reversing the $35 million operating income reported in Q3 2020.
• Depreciation and amortization expense in Q3 2025 includes approximately $100 million of incremental depreciation related to the planned cessation of refining operations at the Benicia refinery next year. This is expected to continue impacting results for two additional quarters (Q4 2025 and Q1 2026).
• Management cited that the renewable diesel segment faces policy and feedstock uncertainties, specifically noting that "the PTC changing Jan. 1 on all foreign feedstocks as well as SAF, that will be a challenge as we start 2026."

TAKEAWAYS

• Net Income -- $1.1 billion, or $3.53 per share for Q3 2025, representing a substantial increase from $364 million, or $1.14 per share in Q3 2020.
• Adjusted Net Income -- Adjusted net income was $1.1 billion, or $3.66 per share, for the third quarter of 2025, compared to $371 million, or $1.16 per share, for the third quarter of 2020.
• Refining Segment Operating Income -- The refining segment reported $1.6 billion of operating income for the third quarter of 2025, compared to $565 million for the third quarter of 2020. Adjusted operating income was $1.7 billion for the third quarter of 2025, compared to $568 million for the third quarter of 2020.
• Refining Throughput -- Averaged 3.1 million barrels per day with 97% utilization, a record for the Gulf Coast and North Atlantic regions in Q3 2025.
• Refining Cash Operating Expense -- $4.71 per barrel on an adjusted basis in Q3 2025, with guidance of $4.80 per barrel for Q4 2025.
• Renewable Diesel Segment -- Posted an operating loss of $28 million in Q3 2025; sales averaged 2.7 million gallons per day during the quarter.
• Ethanol Segment Operating Income -- $183 million of operating income, with record production volumes of 4.6 million gallons per day in Q3 2025.
• Return of Capital -- $1.3 billion was returned to shareholders in Q3 2025: $351 million in dividends and $931 million through the repurchase of approximately 5.7 million shares, resulting in a 78% payout ratio for the quarter.
• Year-to-Date Payout -- Over $2.6 billion was returned to shareholders, equating to a 68% payout ratio year-to-date in 2025.
• Available Liquidity -- $5.3 billion of available liquidity (excluding cash) as of Q3 2025, supported by $8.4 billion in total debt and $4.8 billion in cash and equivalents; The debt-to-capitalization ratio, net of cash and cash equivalents, stood at 18% as of September 30, 2025.
• Sustaining vs. Growth Capex -- Of the $409 million invested in Q3 2025, $364 million was allocated to sustaining operations, with the remainder directed to growth initiatives; capital investments attributable to Valero totaled $382 million in Q3 2025.
• Outlook on Refining Throughput -- Guidance for next quarter: Gulf Coast at 1.78‑1.83 million, Mid-Continent 420‑440 thousand, West Coast 240‑260 thousand, and North Atlantic 485‑505 thousand barrels per day for Q4 2025.
• Benicia Refinery Closure Impact -- is expected to affect quarterly earnings by approximately $0.25 per share over the next two quarters (Q4 2025 and Q1 2026).
• FCC Unit Optimization Project -- $230 million investment at Saint Charles refinery on schedule for commissioning in the second half of 2026; expected to enhance production of higher-value products, including high-octane alkylate.

SUMMARY

Valero Energy (NYSE:VLO) management expects refining fundamentals to remain supported by limited global capacity additions, with guidance indicating an ongoing supply-demand tightness even as new plants come online internationally. Direct commentary attributed narrowing and now-widening quality differentials between medium and heavy sour crudes to market events including increased OPEC and Canadian production, as well as heightened geopolitical disruptions and sanctions. Ethanol operations achieved record production levels, benefiting from a strong corn crop and robust global demand fueled by rising adoption rates in multiple countries. Renewable diesel profitability was adversely affected by unfavorable feedstock economics and ongoing U.S. policy headwinds, though management noted margin improvement into the beginning of the fourth quarter due to falling feedstock costs and sector rationalization. Strategic intentions were clarified regarding the impending Benicia refinery closure, with management stating that all contractual wholesale supply obligations will be met through global waterborne imports after the facility closes.

• Gary Simmons emphasized, "WCS is now trading at a 12% discount to Brent, Maya at a 14% discount," with expectations that these quality differentials will continue to widen if market conditions persist.
• Greg Bram stated, regarding diesel yields, that 38%, 39% is not too far from where we have run in the past, signaling the outlook for continuing high distillate yields given current hardware and operational strategy.
• Eric Fisher described the renewable diesel segment’s challenge: "the PTC changing January 1 on all foreign feedstocks as well as SAF, that will be a challenge as we start 2026."
• Management reported a payout strategy where "effectively all excess free cash flow goes towards share buybacks," reinforcing a disciplined approach to capital returns.

INDUSTRY GLOSSARY

• TMX: Trans Mountain Expansion pipeline delivering Canadian crude primarily to the West Coast of North America and Asian export markets.
• DGD: Diamond Green Diesel, Valero’s joint venture for renewable diesel production.
• RVO: Renewable Volume Obligations, annual quotas set by the EPA for blending renewable fuels into U.S. transportation fuel supply.
• PTC: Production Tax Credit, a policy mechanism providing an incentive per unit of renewable fuel produced, relevant to U.S. biofuels markets.
• SAF: Sustainable Aviation Fuel, a renewable substitute for conventional jet fuel.
• D4 RINs: Compliance credits generated for each gallon of biomass-based diesel produced, used to demonstrate compliance with the EPA’s Renewable Fuel Standard.
• Jones Act: U.S. law requiring goods shipped between U.S. ports be transported on ships that are U.S.-built, -owned, and -operated, impacting refined product flows.
• ARBs: Arbitrage opportunities; in refining, refers to profit potential from moving products between markets with price differentials offsetting transport/logistical costs.
• RVP: Reid Vapor Pressure, a standard measure of gasoline volatility affecting seasonal gasoline blending specifications.

Full Conference Call Transcript

Operator: Welcome to Valero Energy Corporation's third quarter 2025 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, please press Star Zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. You may begin.

Homer Bhullar: Good morning, everyone, and welcome to Valero Energy Corporation's third quarter 2025 earnings conference call. I am joined today by Lane Riggs, Chairman, CEO, and President; Jason Fraser, Executive Vice President and CFO; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; as well as several other members of Valero's senior management team. If you have not received a copy of our earnings release, it is available on our website at investors.valero.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 any 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, Homer, and good morning, everyone. We are pleased to report strong financial results for the third quarter, highlighting our long-standing track record of operational and commercial excellence. Our refinery throughput utilization was 97%, with the Gulf Coast and North Atlantic region setting new all-time highs for throughput following last quarter's record performance in the Gulf Coast. Refining margins remained well supported by strong global demand and persistently low inventory levels despite high utilization rates. Supply constraints were driven by refinery rationalizations, delayed ramp-up of new facilities, and ongoing geopolitical disruptions. These market dynamics contributed to the margin strength despite relatively narrow sour crude differentials. The ethanol segment also delivered a strong quarter, achieving record production and solid earnings.

Strategically, we continue to make progress on the FCC unit optimization project at our Saint Charles refinery. This initiative will enhance our ability to produce high-value product yields, including high-octane alkylate. The $230 million project is expected to begin operations in the second half of 2026. Looking ahead, refining fundamentals should remain supported by low inventories and continued supply tightness with planned refinery closures and limited capacity additions beyond 2025. Our crude differentials are also expected to widen with the increased OPEC and Canadian production. Closing, our strong financial results and record operating achievements this quarter are a testament to our commitment to commercial and operational excellence.

This, coupled with the strength of our balance sheet, should continue to support strong shareholder returns. So with that, Homer, I will turn the call back over to you.

Homer Bhullar: Thanks, Lane. For the third quarter of 2025, net income attributable to Valero stockholders was $1.1 billion, or $3.53 per share, compared to $364 million, or $1.14 per share, for the third quarter of 2020. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders was $1.1 billion, or $3.66 per share, for the third quarter of 2025, compared to $371 million, or $1.16 per share, for the third quarter of 2020. The refining segment reported $1.6 billion of operating income for the third quarter of 2025, compared to $565 million for the third quarter of 2020.

Adjusted operating income was $1.7 billion for the third quarter of 2025, compared to $568 million for the third quarter of 2020. Refining throughput volumes in the third quarter of 2025 averaged 3.1 million barrels per day, or 97% throughput capacity utilization. Adjusted refining cash operating expenses were $4.71 per barrel. The renewable diesel segment reported an operating loss of $28 million for the third quarter of 2025, compared to operating income of $35 million for the third quarter of 2020. Renewable diesel segment sales volumes averaged 2.7 million gallons per day in the third quarter of 2025.

The ethanol segment reported $183 million of operating income for the third quarter of 2025, compared to $153 million for the third quarter of 2020. Ethanol production volumes averaged 4.6 million gallons per day in the third quarter of 2025, achieving record production. For the third quarter of 2025, G&A expenses were $246 million. Net interest expense was $139 million, and income tax expense was $390 million. Depreciation and amortization expense was $836 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery next year. Net cash provided by operating activities was $1.9 billion in the third quarter of 2025.

Included in this amount was a $325 million favorable impact from working capital, and $86 million of adjusted net cash used in operating activities associated with the other joint venture members' share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.6 billion in the third quarter of 2025. Regarding investing activities, we made $409 million of capital investments in the third quarter of 2025, of which $364 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business, including capital investments attributable to the other joint venture members' share of DGD and other variable interest entities.

Capital investments attributable to Valero were $382 million in the third quarter of 2025. Moving to financing activities, we returned $1.3 billion to our stockholders in the third quarter of 2025, of which $351 million was paid as dividends and $931 million was for the purchase of approximately 5.7 million shares of common stock, resulting in a payout ratio of 78% for the quarter. Year to date, we have returned over $2.6 billion through dividends and stock buybacks for a payout ratio of 68%. With respect to our balance sheet, we ended the quarter with $8.4 billion of total debt, $2.2 billion of total finance lease obligations, and $4.8 billion of cash and cash equivalents.

The debt-to-capitalization ratio, net of cash and cash equivalents, was 18% as of September 30th, 2025. And we end the quarter well-capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2025 to be approximately $1.9 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.

For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.78 to 1.83 million barrels per day, Mid-Continent at 420 to 440,000 barrels per day, West Coast at 240 to 260,000 barrels per day, and North Atlantic at 485 to 505,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.80 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 258 million gallons in the fourth quarter, reflecting lower production due to economics. Operating expenses should be $0.52 per gallon, including $0.24 per gallon for non-cash costs such as depreciation and amortization.

Our ethanol segment is expected to produce 4.6 million gallons per day in the fourth quarter. Operating expenses should average $0.40 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the fourth quarter, net interest expense should be about $135 million. Total depreciation and amortization expense in the fourth quarter should be approximately $815 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia refinery next year.

We expect this incremental depreciation related to the Benicia refinery to be included in DNA for the next two quarters, resulting in a quarterly earnings impact of approximately $0.25 per share based on current shares outstanding. For 2025, we still expect G&A expenses to be approximately $985 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. Thank you. The floor is now open for questions. If you would like to ask a question, please press Star One on your telephone keypad.

At this time, a confirmation tone will indicate that your line is in the question queue. You may press Star Two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. Our first question today is coming from Sam Margolin of Wells Fargo. Please go ahead.

Sam Margolin: Hey, good morning, everybody. Thanks for taking the question. This is a comment from your opening remarks. As you mentioned, not much of a contribution from heavy crude this quarter on differentials. I guess we are like a year into TMX barrels sort of fully flowing. I wonder if you could share any insights you have into the differential side, as you know, kind of 12 months into TMX and then just on the overall kind of availability picture that's emerging into 2026.

Gary Simmons: Yeah. So I would tell you, you know, we have been somewhat, I'll start with TMX, somewhat disappointed that TMX has not had as much of an impact on West Coast crude values and has really as did not come off like we anticipated it would. Most of those barrels are flowing to the Far East. In the broader sense, in terms of quality differentials, we have seen the quality differentials move quite a bit. WCS is now trading at a 12% discount to Brent, Maya at a 14% discount to Brent. Those have been as narrow as 7% previously in the year.

On medium sours, we had seen discounts as narrow as 2.5%, that's widened out closer to an 8% discount. So discounts have certainly moved to the point where we are seeing an economic benefit in our system to running medium and heavy sour crudes. Our expectation is you will continue to see those widen. Although OPEC began unwinding their production cuts in April, much of that volume was offset by an increase in summer power burn. So it was not really until September that we saw any meaningful increase in the export volume from OPEC. The pricing signals are there still suggest that most of that incremental OPEC volume will be directed towards Asia.

However, we have been seeing increased offers to the US market, especially for Iraqi crude. We will be processing both Basra and Kirkuk during the fourth quarter in our system. The arbitrage to move Mars into Asia has closed. Additionally, we are starting to see Asia push back on some of the Latin American grades, which ultimately is beginning to pressure medium sours in the Gulf Coast. So all of those effects are things that we are starting to see. In October, then, as medium sour discounts widen, you will see heavy sours react, remain competitive with medium sours. So we anticipate that to continue to happen as we move through the fourth quarter.

In addition to just OPEC, heavy Canadian production has continued to ramp up, as well as some of the deepwater medium sour production in the Gulf. And then you have seen Chinese demand has been very high for medium and heavy sour barrels as they fill their SPR. At some point in time, you would expect that to be full and they would back off. I think the real wildcard here is with the headlines on ramp up in Russian sanctions yesterday. In the past, we felt like sanctions were largely ineffective. They just result in a change in trade flows.

At least if you see the market reaction today, the market believes this round of sanctions could be successful and result in some Russian oil being taken off the market. On paper, OPEC has the capacity to make up that lost supply, but that certainly could be a headwind to quality differentials. However, it would be very bullish for product cracks.

Sam Margolin: Okay. Well, all that color. I guess we will keep it on industry macro for a second, if that is okay. And just on the capacity queue globally next year, we have encountered some feedback about what looks like a fairly heavy schedule of capacity additions next year after a number of years of kind of trailing demand or lagging demand. If you have any insights onto the timing of the capacity additions or what you think we can expect reliability-wise or just a change in balances, that would be much appreciated. Thank you.

Gary Simmons: Yes. So our numbers would show about 460 barrels a day of total light product demand growth next year. Net capacity additions are about 415,000 barrels a day. So those numbers, if you assume somewhere around an 80% total light product yield on crude, you would still have tighter supply-demand balances next year than what you have this year. In addition to that, I think a lot of the forecasts you see assume that new capacity that started up is going to run at nameplate. We have not seen them be able to get up to nameplate yet. And our expectation is a lot of that capacity will not hit nameplate next year.

And then Russian capacity is a real wildcard here also. 1,000,000 barrels a day of Russian capacity offline. A lot of the forecasts assume that Russian capacity is up and running. Beginning of the year. Our expectation is it will take longer to get that up and running as well. So we expect things to be tighter next year as well. Thank you.

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

Manav Gupta: Good morning. I just quickly wanted to follow-up on that. We are seeing a massive spike in global outages. Russia, Dangote, Dasburg, I think over the weekend, there were issues, you know, where you had Romania having issues. So what are you seeing in terms of global product markets out there all these outages and what they are causing for the margins out there you could talk a little bit about that?

Gary Simmons: Manav, this is Gary. I think we have seen good export demand all year. The fact that we have been unable to restock inventories in the United States is keeping somewhat of a pull into the domestic market, but the export markets are very good. Continue to see really good export demand gasoline into Latin America and South America. On the diesel side, a bigger pull into South America than what we have been seeing. Freight has really been volatile. And so on the export ARBs going to Europe, it has kind of been up and down and it is really just freight that kind of been what opens and closes that ARB.

If you look today, that arb is marginally open. And I think you will start to see a heavier flow going to from the U.S. Gulf Coast on diesel.

Manav Gupta: Perfect. My quick follow-up is on the capital return returns, a big jump in the buybacks and should we assume if margins remain well above mid-cycle like they are then your payout ratio remaining the same you would continue to buy back your stock as you did in the third quarter. If you could talk a little bit about the capital discipline as well as the return to shareholders?

Homer Bhullar: Yes. Hey, Manav. It is Homer. Absolutely. I mean, we have talked about this for the last several quarters. We have been in this mode where effectively all excess free cash flow goes towards share buybacks. And you saw that this quarter as well. You had a small build in cash, but that was largely because of working capital. But I think you should continue to assume that we stay in that mode where any excess free cash flow goes for share repurchases.

Manav Gupta: Perfect. You have done exactly what you had said that excess cash will go to shareholders' store. Thank you for that. Thank you, sir.

Homer Bhullar: Thanks. Thanks, Manav.

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

Neil Mehta: Yes, morning team. Lane, there has been a lot of talk about crude that is on the water and in transit and some estimates have it north 3,000,000 barrels a day if you look at some of the shipping tracking data. You guys have unique visibility into whether that crude is actually on the water. And so I would be curious how your commercial team is seeing it. You think it is going to land here in OECD or if that moves into specifically. And I say that in the spirit of to your point of crude differentials potentially starting to widen out, do you start to see that as the factor that could be the catalyst?

And maybe you could talk about Iraq in particular because that could be a leading indicator.

Homer Bhullar: Hey, Neil, I am going to sort of pass the ball over to Gary to answer that question.

Gary Simmons: Yes, Neil, I kind of alluded to that a little bit previously, but where we see the big change is a lot more Rocky barrels flowing this way. As I mentioned, we have bought Basra. We have also bought Kirkuk and we see that to be a portion of our diet in the fourth quarter and moving forward is really the big change that we have seen. Most of the other barrels seem to be making their way to Asia.

Neil Mehta: All right. Well, keep on watching. And then the other question is just on some of the non-refining businesses. Did better than we expected this quarter. Ethanol continues to perform well. And I guess DGD is getting closer to profitability. So can you talk about both of those businesses and whether we are there sustainability at the ethanol margins and whether post the RVO, we are on a path back to the black in DGD.

Eric Fisher: Yes. Hey, Neil, this is Eric. Ethanol continues to look positive. Think a lot of that is we have had a record corn crop. Ethanol demand has been strong both domestically and in the export markets. We are seeing the continued interest in countries going from E0 to E10. Canada has gone to E15 and some of the provinces. And you see Brazil and India looking at moving from the E20s to the E30s. And so all of this is creating more ethanol demand in the world. And being the largest exporter of ethanol, that favors our segment pretty well. So cheap feedstock and lots of demand.

So ethanol, I think outlook is good and continues to look good in the future. On DGD, you are exactly right. We have seen throughout the year, there has just been a lot of impact from tariffs and policy downturns in the U.S. We have seen fat prices rising for the better part of the year. And I think just most recently, we are seeing enough rationalization in both biodiesel and renewable diesel where fat prices are finally starting to soften. And with that lower fat price, we have seen DGD margins return back to positive EBITDA. So that is a good sign. That is a good sign for the fourth quarter.

Obviously, the PTC changing January 1 on all foreign feedstocks as well as SAF, that will be a challenge as we start 2026. But I think everyone seems to expect that the RVO will be net positive for Renewables. That is a lot of speculation because there is a lot of back and forth on policies right now. But I think the general view is the number is probably going up and will probably be supportive of renewable diesel.

Neil Mehta: Thanks, Eric.

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

Theresa Chen: Good morning. I wanted to talk about your PADD III and PADD II assets and in light of two major product pipeline bindings open seasons that have been announced over the recent weeks to move more volumes from the regions into PADD five given ongoing West Coast refinery closures including your own Venetia facility. So if one of these 200,000 barrels per day plus systems were to be built, do you anticipate this could reshape flow flows and margin capture across your Gulf Coast and Mid Continent assets? And is there any volition? Would it make sense for you to be a shipper on one of these pipes?

Gary Simmons: Yes. Theresa, this is Gary. We engage in conversations with both the projects that we think could go forward. In both cases, we will have to wait and see what the final tariff numbers are. It looks like the tariff would be set such that it is competitive versus the Jones Act movement to the West Coast. But we believe we can be more competitive with foreign flag waterborne movements into the West Coast. In addition to that, we like the waterborne movements because one, the volatility on the West Coast, you take a position on that pipe, could be shipping into a closed arb a good portion of the time.

And then we like the waterborne option as well because it allows you to source barrels from anywhere in the world and take advantage of international ARBs that can be open. So we have connectivity through McKee already to El Paso and into Phoenix. So we have a lot of that connectivity as well as space on the pipe from Houston to El Paso. So I do not think you will see us participate in those projects.

Lane Riggs: Hey, this is Lane. The second part of that would be, you would expect that firm up the group in the Gulf Coast. It is barrels do get committed and move west assuming those projects go through.

Theresa Chen: Thank you. That is very helpful. And separately, Gary, there has been some noise in the DOEs as of recently. Love to get your take on what you are seeing across your domestic distribution channels and your commentary on domestic demand in addition to the color you gave already on exports?

Gary Simmons: Sure. If you look at our gas demand, think in our system, we would say year over year gasoline demand is flat to slightly down, pretty similar to what is in the DOEs. Third quarter, our volumes were flat year over year. It looks to us like vehicle miles traveled are up year over year, but probably not enough to offset the more efficient automobile fleet. So again, probably flat to slightly down gasoline demand. As I mentioned, export demand looks good.

When you look at gasoline fundamentals in addition to good export demand, the Transatlantic arb to ship from Europe into New York Harbor is closed, and it is actually closed on paper all the way through the first quarter. So really for this time of year, gasoline fundamentals look about as constructive as you could hope for. Obviously, we have transitioned out of driving season, producing high RVP winter grade gasoline. So you would not expect a lot of strength in gasoline cracks in the fourth quarter. Jet demand, we are continuing to see good nominations from the airline.

So again, comparing to the DOEs, which show about a 4% bump in jet demand, that looks consistent with what we are seeing in the market. And then finally on diesel, in our system, the third quarter, year over year sales were up 8%. I do not think that is representative of the broader market. DOE data is showing about a 2% year over year increase in diesel demand is probably close. We have seen good agricultural demand in our system that continues harvest season starting to wind down, but then you will start heating oil season, which again be good pop in demand.

And as I mentioned, good export demand as well volatility is hindering that, but the demand is there.

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

Doug Leggate: Hey, good morning, everyone. Thanks for taking my questions. Lane, your throughput performance has been extraordinary again. And my question is kind of a bigger picture. I guess it is kind of a machine learning kind of question. And I am wondering if there is a change going on in how you are running your business, things like planned turnarounds just in time as opposed to the behavioral once every four year kind of deal? Is there anything happening that would lead us to think some of this throughput performance could be sustainable, not just for you, but perhaps for the broader industry?

Lane Riggs: Doug, I am going to have Greg Ram sort of start off on this question.

Greg Bram: Hey, Doug. So the journey you are talking about relates to how we plan turnarounds, we have embarked on that for gosh, probably at least a decade. So I would not say there is a shift there, but we definitely have reaped some benefits from the kind of the approach we take now, which aligns with kind of the way you described it. But if you want to talk about AI in general, I would say that we are probably cautiously optimistic about how that can help us further improve our availability. We are evaluating a number of places where we could use that technology.

As you would expect, focusing on areas where we think we can create some tangible value and we have deployed that in some of those new techniques in a few applications. But I think one of the key learnings that we have picked up as we have embarked on looking at AI machine learning applications is that you really have to have good quality data of your operation to have successful use of that kind of a tool. I think it is an advantage for us because we embarked on an effort to improve that data and gather that data in kind of a consistent way, kind of consistent practices across our system, again probably ten or fifteen years ago.

And so having that data makes it makes the opportunity to try to use that to make further improvements more real. And so we start from a good place. You have mentioned quality of our operation today. Good performance to start with. But again, optimism that AI type techniques can help us make some further improvements.

Doug Leggate: I appreciate the answer. Guess we are trying to figure out if we should lift our expectations of mid-cycle throughput for Valero. I guess that was at the root of my question, but I appreciate the insights. My follow-up, and I apologize to Homer specifically because I have had a couple of chances to talk to him this morning about this already. But I am trying to understand what is going on with cash flow because your tax rate is obviously up a little bit on mix. But if we look at the translation of your earnings to your cash flow, a big beat on earnings did not show up in cash flow.

And we are trying to figure out if there are some transitory issues in there. Necessarily go into all the specifics, but is cash tax part of that or was there another reason?

Homer Bhullar: Hey, Doug, it is Homer. I mean, you will see this when you see the some like PTC, for example, you book it within earnings and then obviously the payment comes in later. So you will see that as a deduct from net cash flow from operations. So that is of the big variances. Again, you will see that when you see the statement of cash flows in the key.

Doug Leggate: So no tax issue, Homer? No temporary tax issues. All right. We will have to wait in the queue. Thanks so much, guys. Appreciate it.

Operator: The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.

Ryan Todd: Maybe one on refining utilization. U.S. refining utilization has been quite strong versus historical norms over the last six months. Any thoughts on drivers of this, whether it is an impact of exiting a period of heavy maintenance over the last couple of years, and any thoughts on whether like suggestions that this or it would prevent this from normalizing as we head into next year or other reasons to believe that we can the U.S. system can continue to run-in running this hard?

Lane Riggs: Hey, Ryan, this is Lane. So you are talking about just the U.S. industry refining utilizations improved over the last few years?

Ryan Todd: Yeah. I mean, it has been very strong this year, like over the last four or five months.

Lane Riggs: Well, I will start and let Gary or Greg tune me afterwards. I think we started on the journey, I am going to say fifteen years ago to work extensively on our reliability and we actually showed that this could be done. Think a lot of the rest of the industry is sort of working on the same things and they are getting better at it and being more careful in their execution.

The systems are getting better whether like the previous question, from Doug, how many people are using something that they might call AI, I do not know, but there are systems out there to let you execute turnarounds better, do your maintenance better, have some predictive capabilities with respect to failure mechanisms, which all act improves what we actually term as availability even through even better scheduling things like this. And I think generally the industry has done a little better job on this. So that is how I would answer it.

Ryan Todd: Only thing I might add just maybe the only thing I would add only thing I think about when I think about this past summer versus some of the previous periods is we did not really have a lot of extreme weather throughout the summer. And refineries run well when you kind of got nice ambient conditions. And so I think we all have been incented to run hard for throughout these different periods. It could be maintenance part of it. It could just be that when you are not dealing with a lot of really hot temperatures, you can tune up the operation and eke out that last little bit. So I do not have proof of that.

But when I think about how our operation runs, I can see that being a positive impact this past summer.

Lane Riggs: Well, that is a great point. Hurricane, we have not had any hurricane activity to speak of in the call.

Ryan Todd: Right. Thank you. And maybe one other, as we think about the fourth quarter here, during the third quarter, were a number of things that were mean, you had a great quarter, but there are a number of things that were kind I would say, like modest headwinds on margin capture, whether it was narrow crew differentials, crude backwardation, some West Coast jet fuel dynamics and secondary products, etcetera? Many of these appear to reverse or improve early on in the fourth quarter. Any thoughts on direction of some of these trends that may impact the type of capture or profitability that we see during the fourth quarter and what looks like a pretty strong environment?

Greg Bram: Yes, Ryan, it is Greg. It is early for the fourth quarter, right? And you did mention a few of the things that have turned more favorable as we have gotten started out here in October. A couple of things I always think about as we approach the winter season, we will blend more butane into gasoline as RVP shifts to winter specifications. That tends to create some uplift on margin capture. But I think it is also worth knowing while there have been a number of things that have moved favorably, you still have some pretty weak secondary products. Naphtha has turned a bit weaker. Propylene continues to be fairly weak.

So there are a few things out there that have not really turned positively yet as we started out in the quarter.

Ryan Todd: Great.

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

Paul Cheng: Hey guys, good morning. Just before my question, just curious that and have a comment I was surprised that you guys did not increase your G and A full year. I thought with the strong earnings that you guys going to increase your bonus accrual. So I was surprised, that is a part of the cost saving from.

Lane Riggs: Yeah. Well, that is not one we would eagerly jump on.

Paul Cheng: I told Homer that this is not going to be kind as my question. But anyway, Look out that as a good comment, Paul.

Homer Bhullar: Okay. My question is actually that in the third quarter, I think part of the issue related to the margin capture is on the off team. Value. Comparing to the second quarter, I think has come down. Just curious that if you guys be able to share some insight what happened and then what do you think that will continue that trend? Secondly, I want to go back into not so much about just AI, but also robotic technology and all that.

So Lane and the team, Greg, do you guys think that we are seeing all this new technology now available to you is more the evolution or that is going to transform the way how you guys may conduct business, not just in the refining side, but also in your back office in your trading, commercial as such that, I mean, have seen your upstream counterparts, some of them that announced some pretty sizable cost reduction net for because of the new technology. So I want to see where we stand for you guys or for the industry.

Gary Simmons: So maybe I will take the NAFTA question and let Greg take the second one. Yes. So or the octane question, sorry. When we look at octane, we tend to view that it trades at an inverse to naphtha. So what you really had in the last quarter was naphtha got a little bit stronger. And I think there are several reasons for that. You had less naphtha coming out of Russia. You had some of the naphtha from the U.S. Gulf Coast going back to Venezuela as diluent. And then you are seeing a little bit more naphtha pull to Asia into the petchem market.

So when naphtha is weak, there is a big incentive to try to blend it into gasoline and that takes octane to do it. But when naphtha gets stronger, there is less of an incentive. So although the regrade octane regrain was a little bit weaker, it probably helped set up stronger gasoline fundamentals.

Greg Bram: All right, Paul. And so this is Greg. On the question around robotic automation and AI, I think maybe we do not talk about this a lot, but we have been using those techniques and further expanding the use of those techniques over time. As again as they make sense in terms of improving efficiency. And it improves our ability to inspect equipment certainly to execute some of the work that we do. So that will continue to grow I suspect. And some of these new techniques will create more opportunity to use those tools going forward, which is kind of back to the answer before.

I think there will be some improvement that comes from this some of this new technology and these new techniques that are out there. And it will be if you start from a really good place like we do, it is going to be harder to find a lot of big opportunities there. But we are certainly focused on trying to find ones that make good from a value standpoint. And Paul, I will add to it. The only thing you know some examples of those things is we like many other people in the industry have been using robotic with respect to tank cleaning. I can see where the upstream guys would really that would really help them.

The other thing that we have used is drones for inspection like if you go into today we get into a big structure on an FCC and we can actually just really have to get in scaffold up to a particular location that might be problematic. We can put a drone in float up, look at it, understand that situation without having to we may have to go back in and put scaffolded, but now we understand the scope of work. So there are certainly things like that.

And then with NR systems, we are always trying to think about ways to consolidate our control rooms and work on being more efficient with the operators that we have and some of which has to do with technology improvement.

Paul Cheng: Great. Thank you.

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

Joe Laetsch: Great, thanks. Good morning and thanks for taking my question. So I want to start on the refining side and with the strength in the diesel crack, can you talk about the ability to maintain the strong, I think it was 38% or 39% diesel yield level going forward? And then as part of that, the crude slate got a bit lighter quarter over quarter, but diesel yield also stepped up, which I was hoping you could talk to as well. Thank you.

Greg Bram: So I will take I will start with the second one, I think. So well, actually, I can probably cover both of them. Yeah. Joe, we have had strong diesel yield. That 38%, 39% is not too far from where we have run-in the past. It reflects a mode of operation where we are maximizing diesel production or just distillate production over gasoline. Again, we kind of tuned up the operation and ran very well in the quarter, I think you saw us reach some of the highest levels that I think we can achieve with the current hardware we have. So sustainable, we can probably stick in this range. With continued strong operations like we had.

Remind me Joe, what was the second part of that question?

Joe Laetsch: Yes. So I was just asking about the crude slate got a bit lighter quarter over quarter, but able to step up the distal yields. So just hoping to get a little bit of thoughts on.

Greg Bram: Yes. We did get a little bit lighter, but think in some of the places where we lightened up, we were still able to the growth was more on the jet side than on the diesel side. We were able to kind of drop that back into the naphtha into the jet, still make a distillate product and had good incentive to do so. So I am not sure that the slate itself if I were to try to back in and I have not tried to back into what was the total available distillate yield. I do not know that it was a big enough shift in some of the places where we got lighter.

That would have had a material impact on our distillate. Our yield there.

Joe Laetsch: Great. That is helpful. And then, Eric, I want to shift to RD and then just wait for clarity on the RVO and the SRE reallocation. Can you talk to how you are thinking about the path for D4 RINs here? And then as part of that, is there a level that you think it needs to rise to incentivize the marginal producer?

Eric Fisher: Yes. I think it is one of those things where there are more than knowns. I mean, so but there are any number of combinations of a number, an SRE, a reallocation and final number. But any combination of those numbers the current number is $3,300,000,000 D4s. I think if you go back and look at the original premise of keeping the BD producer breakeven with $1 BTC, they have done a lot of work this year with removing EyeLock out of the model. For soybean oil. They gave a small producer benefit, which I think counts almost every single BD producer. And I think they are around seven to $8 versus that dollar last year.

So this last $0.20 is probably, if you took that to a D4 RIN, you probably need RINs to go up something like $0.25 to $0.30 to get BD back to breakeven. So that is kind of how I see. So any combination of the math that gets to that kind of number essentially satisfies the original design of trying to keep BD operational. What that number translates out to RINs is a number higher than today. Although one of the challenges I think is they are trying to figure out this math is 25 D4 RIN production is down versus last year. So we have a current target of 3.3.

If we underperform that number, we will consume the bank early into next year. So depending on how high you set that number, it is very difficult to pick where you will meet that BD requirement, but not overshoot and then create an impact to overall diesel prices. So I think that is kind of the challenge of how this works. But if I try to anchor on something I go back to the dollar BTC and where was the BD producer and where are they today. And so I think there is still a gap there.

And clearly with the trade issue with China and soybean oil, and soybeans in general, how that plays into this is really difficult to predict. But I think the math is something like that.

Joe Laetsch: Great. Thanks. Yes, I realize there is a lot of moving pieces, I appreciate your thoughts. Thanks.

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

Phillip Jungwirth: Thanks. Good morning. Specific to the heavy sour mix in the Gulf Coast, can you just through the moving pieces here with Mexico production declining, the Venezuelan certainty? Assume that was not any help in the quarter. And also just Canada TMX capacity and then also just how fuel imports might be helping replace some of these barrels in Gulf Coast system? And maybe also just touch on coker margins with high diesel cracks, but also still tight differentials.

Gary Simmons: Yes. So overall, yes, we do see declining production from Mexico. Our volumes from Mexico are not really down much yet, but they continue to forecast that we will see declining production from Mexico. A lot of that is being made up with additional volumes from Canada as they continue to ramp up production in fill the pipeline capacity coming to the Gulf. So I would say those somewhat offset each other. We do have Venezuelan barrels back in the mix, which is helping.

And then the additional OPEC production, as I alluded to getting the Bossa barrels and Kirkuk barrels, all that really I think you will see in the fourth quarter a heavier crude diet than what we had in the third quarter filling out a lot of our conversion capacity. On the high sulfur fuel oil question, actually high sulfur fuel oil has been pretty strong and we have not seen a real strong incentive to buy high sulfur fuel to put into cokers. There has been some opportunistic purchases, but for the most part, on paper those economics have not been strong.

Phillip Jungwirth: Okay, great. And then on the planned Venetia closure, you did have the charge in the quarter. Recognizing the state would like to keep this open and the official close date is not in April. But when do you kind of reach the point of no return here just given preparations needed and the scheduled turnaround?

Rich Walsh: This is Rich Walsh. I will take an for Tim. To answer at least interaction with the government part of it. I mean we have been in discussions with California, but nothing has materialized out of that. And so as a result nothing changed. Our plans are still moving forward as shared and as we have informed the state. So I do not see anything changing on that.

Phillip Jungwirth: Great. Thanks.

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

Matthew Blair: Could you talk about DGD performance so far in the fourth quarter? I think your indicator is up quite a bit, maybe $0.36 a gallon quarter over quarter. Are you realizing that improvement so far? Or are there other factors we need to take into account, like hedging or feedstock lag or I think some of the staff credits changed on October 1. But yes, just any sort of broader commentary on DGD so far. In Q4 would be great.

Eric Fisher: Yes. I think most of that I would say is tied to lower feedstock prices. I think you are seeing rationalization and feedstock prices starting to come off. And so a lot of that is improving the profitability of DGD. We still have strong staff benefits both in the U.S. and in the European and UK markets. So that is an advantage that DGD has over a lot of other RD producers. And SAF has a premium in the base. And so fourth quarter looks good from an overall production rate standpoint as well as just PTC capture and on lower fat prices is really the fourth quarter.

I think the question is still going to be as we enter into 2026, will you see adequate premiums on SAF to cover the loss of the PTC benefit? And are you going to see as we were we have discussed a couple of times what is going to be the RVO impact because that will have to be the vehicle to make up any gap in profitability for biodiesel and renewable diesel to comply with wherever the RVO gets set. And so we still have a lot of policy that appears to be in conflict of increased RVO, but decreased generation because of foreign feedstocks.

Those are all going to be things where you are trying to raise the number, but make it more difficult to generate. That usually is going to mean higher RIN prices. And so I think that is the question that everyone has got to get settled on. And think there is good awareness how these knobs will affect the overall market. But I think those are the two things that will determine whether or not this fourth quarter improved profitability can continue into 2026.

Matthew Blair: Indeed, a lot of moving parts there. And then if I could follow-up on Theresa's question on the new product types that are headed west. Could you talk about what this means for the prospects for your Wilmington refinery? I think Los Angeles currently ships about 125 a day of product east out of the market to Phoenix. If one of proposals goes through, then Angeles could actually receive about 200 a day. So that is a pretty big shift on California supply demand. And do you think Wilmington would be able to compete with an extra 200 a day coming into that Los Angeles market?

Gary Simmons: Yes. This is Gary. I think when we look at the numbers, if you look at the California market today, it looks like it is being set by import parity. And if you look at the tariffs on those pipes, import parity through the pipeline does not look to be significantly different than import parity on the waterborne barrels. So I do not know that you will see much of a change in the California market as a result of the pipelines.

Matthew Blair: Sounds good. Thank you.

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

Jason Gabelman: Hey, thanks for taking my questions. Hopefully two quick ones. First, just on the Russian refining disruptions, there is a lot of headlines on the Ukraine drone strikes, but it does seem like in many cases the refineries come back online quickly. I was wondering if you could provide some numbers around the amount of disruption that you are seeing on Russian product exports and kind of before today, trying to parse out how much of the product strength was driven by actual disruptions versus geopolitical risk premium in the prices? And then my second one is on the Benicia shutdown. Can you talk about your plans to re-market?

Are you going to have to kind of import products from Asia in order to meet your contractual obligations? Or do not have really many outstanding that market once the plant shuts down? Thanks.

Gary Simmons: Yes. I will take the first part of that. I think we do think the drone strikes have been pretty effective. It looks like a lot of what is happening in Russia is that largely attacking some of the higher complexity refining capacity. And so as that happens then Russia will go ahead and ramp up some of the lower complexity refining capacity. So you can kind of see that. With the fuel exports and some of those things. The second part of your question, I think spike we are seeing today is not so much due to any kind of disruption from Russia yet. It is just hype in the market on what could happen in the future.

But we definitely see exports from product exports from Russia falling.

Lane Riggs: Hey, Jason. Is Lane on the second part. Our intent is to continue to supply our contractual obligations for our wholesale business. And after we shut down the refinery.

Jason Gabelman: Okay. And those would be essentially imports from Asia? Presumably?

Lane Riggs: It could be from anywhere in the world. It is just kind of what Gary alluded to earlier. Waterborne allows you to have optionality to try to work ARBs into that short versus maybe having a huge commitment on a pipeline. It is what that is sort of our intent. We are not going to go out and term up barrels from some particular market. We will figure out how to supply it.

Jason Gabelman: Okay. Thanks.

Operator: Thank you. The next question is coming from Nitin Kumar of Mizuho Securities. Please go ahead.

Nitin Kumar: Hi, good morning. Thanks for taking my question. I really just have one other part A and B. You have talked a little bit about the crude spreads widening from here on out. Just maybe some thoughts on what do you see the mid-cycle or so at least twelve months view on some of these spreads because you should have at least based on what is going on between Canada Iraqi barrels you were mentioning, there is to be a lot of supply of heavier crudes coming at the same time to the market.

And then and maybe part B is, given your complexity especially in the Gulf Coast, you have like a buffet of crudes that you could choose from. Is there a specific crude that you think falls to the bottom if it is not discounted appropriately?

Gary Simmons: Yes. So I will just take a stab at that. I guess, our view is without getting into a lot of specifics on what we call mid-cycle, I guess we would say we are the quality differentials are today, it would be a little inside of what we view as mid-cycle and we do see those continuing to widen going forward.

In terms of crude we see falling out, I do not really know that I have a view on that Greg, I do not know if you have one, but what I would probably add, if you look back and I think the market works its way today as well, the Latin American grades are the ones that tend to be the swing. And so they are probably the one that is kind of moved into fill holes when there was a short in the Gulf Coast. So they are probably the first ones that would back out as some of that supply comes in.

Nitin Kumar: Great. Thanks for the answers.

Operator: Thank you. At this time, I would like to turn the floor over to Mr. Bhullar for closing comments.

Homer Bhullar: Thank you, Donna. We appreciate everyone joining us today. And as always, please feel free to contact the IR team if you have any additional questions. Have a great day, everyone. Thank you.

Operator: Ladies and gentlemen, 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.

This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. Parts of this article were created using Large Language Models (LLMs) based on The Motley Fool's insights and investing approach. It has been reviewed by our AI quality control systems. Since LLMs cannot (currently) own stocks, it has no positions in any of the stocks mentioned. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability.

The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy.