The companies on the Global 500 employ 70.2 million people, and their revenue represents more than one-third of the world’s GDP.

Fortune Global 500

With a combined revenue of $21 trillion and $2.1 trillion in profits, the 2026 Fortune 500 is the definitive list of America's largest companies.

Fortune 500

The corporations on our annual list of the world's 500 largest companies combined to generate $41.7 trillion in revenue over the past year.

Almost $20 trillion in revenue—and a record-breaking $1.87 trillion in profits. Introducing the 2025 Fortune 500, the definitive list of the biggest companies in America.

Energy sector dominated this year for the first time since 2008, with 28 companies featured on the list.

100 Fastest-Growing Companies

The corporations on our annual list posted aggregate revenues of $41 trillion for the second year in a row.

Industries included in the sector are mining, oil and gas exploration and services, pipelines, refining, and utilities.

Fortune Sector Leaders: Energy

The Fortune 500, in its 70th year in 2024, ranks the biggest U.S. companies by revenue.

The corporations on our annual list of the world’s largest companies delivered a record $41 trillion in aggregate revenues.

G500-2023-Valero

Petroleum refining company Valero Energy leaped 42 spots in our ranking this year, bringing in $175.7 billion in revenue, a 53% increase over the previous year. 
<ul> 
 	<li>In May 2023, Valero announced that Joseph W. Gorder would retire as chief executive officer effective June 30, staying on as executive chairman. R. Lane Riggs, Valero’s president and chief operating officer, succeded Gorder.</li> 
 	<li>The company’s refining, renewable diesel, and ethanol segments each reported substantial increases in revenue as of the first quarter of 2023 compared to the year-earlier quarter.</li> 
 	<li>Valero’s Port Arthur Coker project, which the company expects will improve its efficiency by converting residual crude oil into useable fuels, was completed in March 2023 and began operations the month after.</li> 
 	<li>In April 2023, Valero agreed to pay a $1.2 million settlement to the U.S. Environmental Protection Agency after its refinery in Benicia, Calif., violated the federal Clean Air Act.</li> 
</ul>

The Fortune 500, in its 69th year in 2023, ranks the biggest U.S. companies by revenue.

F500 2023-Valero Energy

Petroleum refining company Valero Energy leaped 12 spots in our ranking this year, bringing in $171.2 billion in revenue, a 58% increase over the previous year. 
<ul> 
 	<li>In May 2023, Valero announced that Joseph W. Gorder would retire as chief executive officer effective June 30, staying on as executive chairman. R. Lane Riggs, Valero’s president and chief operating officer, will take Gorder’s place as CEO.</li> 
 	<li>The company’s refining, renewable diesel, and ethanol segments each reported substantial increases in revenue as of the first quarter of 2023 compared to the year-earlier quarter.</li> 
 	<li>Valero’s Port Arthur Coker project, which the company expects will improve its efficiency by converting residual crude oil into useable fuels, was completed in March 2023 and began operations the month after.</li> 
 	<li>In April 2023, Valero agreed to pay a $1.2 million settlement to the U.S. Environmental Protection Agency after its refinery in Benicia, Calif., violated the federal Clean Air Act.</li> 
</ul>

Aggregate sales hit $37.8 trillion last year—an increase of 19%, the highest annual growth rate in the list’s history.

This year’s Fortune 500 marks the 68th running of the list.

F500 2022 Valero Energy Corp

Like other oil and gas companies, refining giant Valero Energy enjoyed a snapback in revenue and earnings in 2021 as pandemic lockdowns eased. Valero has launched a number of low-carbon and renewable fuel projects in recent years, and has pledged to reduce emissions from its refining operations 63% from 2020 levels by 2025. The company’s Diamond Alternative Energy has taken some heat from environmentalists, however, for lobbying for renewable fuels over zero-emissions alternatives; Diamond is a plaintiff in a recent federal lawsuit against Environmental Protection Agency regulations designed to encourage the sale of electric vehicles.

Total revenue for the world’s biggest companies fell 4.8% to $31.7 trillion this year—the first decline in half a decade.

G500-2021-164-VALERO ENERGY

<span data-sheets-value="{&quot;1&quot;:2,&quot;2&quot;:&quot;The U.S. refining sector was battered in 2020 by lockdowns and travel restrictions, pushing the San Antonio–based refiner to a $1.4 billion loss. That compares with 2019’s $2.4 billion profit. One saving grace came from Valero’s renewable fuels business, which capitalized on the push for low-carbon alternatives to fossil fuels. The company now expects to invest half of its growth capital in renewable diesel. As part of its expansion, last year Valero approved a new diesel plant that is expected to begin operations in 2023.&quot;}" data-sheets-userformat="{&quot;2&quot;:12673,&quot;3&quot;:{&quot;1&quot;:0},&quot;10&quot;:2,&quot;11&quot;:4,&quot;15&quot;:&quot;Calibri&quot;,&quot;16&quot;:11}">The U.S. refining sector was battered in 2020 by lockdowns and travel restrictions, pushing the San Antonio–based refiner to a $1.4 billion loss. That compares with 2019’s $2.4 billion profit. One saving grace came from Valero’s renewable fuels business, which capitalized on the push for low-carbon alternatives to fossil fuels. The company now expects to invest half of its growth capital in renewable diesel. As part of its expansion, last year Valero approved a new diesel plant that is expected to begin operations in 2023.

This year’s Fortune 500 marks the 67th running of the list.

F500-2021-53-Valero Energy

This year's Fortune Global 500 generated $33.3 trillion in revenues and $2.1 trillion in profits.

G500-2020-071-Valero-Energy

As CEO Joe Gorder put it when the company released its annual financial report, Valero faced another “challenging environment for the refining business” in 2019. Net income sank 17% year-on-year, to $2.8 billion, even as refinery utilization was at 96% and the company refined record amounts of oil. The business completed a network of central Texas pipelines and terminals, extending the reach of its vast U.S. shale business deeper inland. Its 2020 growth ambitions suffered a blow in late November when its renewable fuels business stumbled: Two ethanol plants were forced to close temporarily, and additional plants went offline in March 2020, as the coronavirus pandemic destroyed demand for any and all types of energy.

This year's Fortune 500 marks the 66th running of the list.

F500-2020-032-Valero-Energy

This year's Fortune Global 500 generated $27.7 trillion in revenues and $1.5 trillion in profits.

This year's Fortune 500 marks the 65th running of the list.

This year's Fortune 500 marks the 64th running of the list.

This year's Fortune 500 marks the 63rd running of the list.

Here are the World's Most Admired Companies for 2016 as ranked in their industries. See who made the list.

World's Most Admired Companies

This year's Fortune Global 500 generated $27.6 trillion in revenues and $1.5 trillion in profits.

This year's Fortune 500 marks the 62nd running of the list.

Business insiders have spoken: Asked which companies they most admire, more than 4,100 executives, directors, and analysts chose these top 50 All-Stars.

The world's 500 largest companies generated $31.2 trillion in revenues and $1.7 trillion in profits in 2014. Together, this year's Fortune Global 500 employ 65 million people worldwide and are represented by 36 countries.

This year's Fortune 500 marks the 61st running of the list. Wal-Mart claims the top spot again. See who made the list.

Global business is back. After limping through a worldwide financial crisis and economic slowdown, the 500 largest companies ranked by revenues shattered all sorts of performance records in 2013: They racked up combined revenues of $31.1 trillion, up 2.5% from 2012, and profits soared 27% to nearly $2 trillion. China’s 95 companies (up from 89 last year) posted $5.8 trillion in revenues. The U.S. has four fewer companies on the list than last year but remains (for now) the country leader, with 128 corporations on the list—including No. 1 Wal-Mart Stores—reporting $8.6 trillion in revenues. 

Wal-Mart stayed on top as its sales crept closer to half-a-trillion dollars. Apple moved into the top five. And UnitedHealth Group continued its steady climb. 

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Valero Energy is an oil refiner with operations in the U.S., Canada, Latin America, and Europe. Founded in 1980, the company sells gasoline, diesel, and ethanol through outlets under the Valero, Beacon, Diamond Shamrock, Shamrock, Texaco, and Ultramar brands.

Q2 2026

Q1 2026

Q4 2025

Q3 2025

Q2 2025

Q1 2025

Q4 2024

Valero Energy (VLO): Company Profile, Stock Price, News, Rankings

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Valero Energy

valero energy

Greetings and welcome to Valero Energy Corp's fourth quarter 2025 earnings call. At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone requires operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Donovan, VP of Investor Relations. Thank you. Please go ahead.

Good morning, everyone, and welcome to Valero Energy Corporation's fourth quarter 2025 earnings conference call. I'm joined today by Lane Riggs, Chairman, CEO, and President; Gary Simmons, Executive Vice President and COO; Rich Walsh, Executive Vice President and General Counsel; Homer Bhullar, Senior Vice President and CFO; as well as several other members of Valero's senior management team. If you have not yet received a copy of our earnings release, it is available on our website at investor.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'll now turn the call over to Lane for opening remarks.

Thank you, Brian, and good morning, everyone. I'd like to begin by highlighting some of our team's accomplishments in 2025. Last year was our best year for personnel safety and environmental performance, building on personnel and process safety records we set in 2024. Our continued commitment to safe, reliable, and environmentally responsible operations resulted in a record refining throughput and record ethanol production for both the fourth quarter and the full year. We also set a record for mechanical availability in 2025. These accomplishments reflect the hard work, expertise, and dedication of our entire team. We delivered strong financial results in the fourth quarter, reinforcing our consistent track record of operational and commercial excellence. We captured favorable refining margins during the quarter, driven by strong product cracks and widening sour crude discounts, and our fourth quarter performance capped off excellent financial results for the year.

Strategically, we continue to make progress on our FCC unit optimization project at our St. Charles Refinery. This $230 million initiative will enhance our ability to produce high-valued product yields, including alkylate. We still expect the project to begin operations in the second half of 2026. Looking ahead, we believe refining fundamentals should remain supported by continued demand growth and a tight supply environment driven by limited capacity additions. Sour crude differentials are also expected to benefit from increased Canadian crude production, along with additional Venezuelan crude supply into the U.S. In closing, Valero's strong financial results and record operating performance highlight our operational and commercial excellence. We remain committed to our disciplined capital allocation framework that prioritizes balance sheet strength, disciplined capital investments, and shareholder returns. With that, I'll turn the call over to Homer.

Thank you, Lane. For the fourth quarter of 2025, net income attributable to Valero stockholders was $1.1 billion, or $3.73 per share, compared to $281 million, or $0.88 per share, for the fourth quarter of 2024. Excluding the adjustments shown in the earnings release tables, adjusted net income attributable to Valero stockholders was $1.2 billion, or $3.82 per share, for the fourth quarter of 2025, compared to $207 million, or $0.64 per share, for the fourth quarter of 2024. For 2025, net income attributable to Valero stockholders was $2.3 billion, or $7.57 per share, compared to $2.8 billion, or $8.58 per share in 2024. 2025 adjusted net income attributable to Valero stockholders was $3.3 billion, or $10.61 per share, compared to $2.7 billion, or $8.48 per share in 2024.

The refining segment reported $1.7 billion of operating income for the fourth quarter of 2025, compared to $437 million for the fourth quarter of 2024. Adjusted operating income was $1.7 billion for the fourth quarter of 2025, compared to $441 million for the fourth quarter of 2024. Refining throughput volumes in the fourth quarter of 2025 averaged 3.1 million barrels per day, or 98% throughput capacity utilization. As Lane highlighted earlier, we achieved record throughput for both the quarter and the full year. Refining cash operating expenses were $5.03 per barrel in the fourth quarter of 2025. The renewable diesel segment reported operating income of $92 million for the fourth quarter of 2025, compared to $170 million for the fourth quarter of 2024. Renewable diesel segment sales volumes averaged 3.1 million gallons per day in the fourth quarter of 2025.

The ethanol segment reported $117 million of operating income for the fourth quarter of 2025, compared to $20 million for the fourth quarter of 2024. Ethanol production volumes averaged 4.8 million gallons per day in the fourth quarter of 2025, also setting a quarterly and full-year record. G&A expenses were $315 million for the fourth quarter of 2025 and $1 billion for the full year. Depreciation and amortization expense was $817 million for the fourth quarter of 2025, which includes approximately $100 million incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery. Net interest expense was $139 million, and income tax expense was $355 million for the fourth quarter of 2025. The effective tax rate was 25% for 2025. Net cash provided by operating activities was $2.1 billion in the fourth quarter of 2025.

Included in this amount was a $349 million unfavorable impact from working capital and $269 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $2.1 billion in the fourth quarter of 2025. Net cash provided by operating activities in 2025 was $5.8 billion. Included in this amount was $192 million unfavorable change in working capital and $30 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $6 billion in 2025.

Regarding investing activities, we made $412 million of capital investments in the fourth quarter of 2025, of which $368 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and the balance was for growing the business. Excluding capital investments attributable to the other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $405 million in the fourth quarter of 2025 and $1.8 billion for the year. Moving to financing activities, we remain committed to our disciplined capital allocation framework. Shareholder cash returns totaled $1.4 billion in the fourth quarter of 2025, resulting in a payout ratio of 66% for the quarter. For the full year, shareholder cash returns totaled $4 billion, resulting in a payout ratio of 67% for the year.

We ended the year with 299 million shares outstanding, reflecting a reduction of 5% for the year and 42% since 2014. Earlier this month, our board approved a 6% increase to the quarterly cash dividend, slightly higher than last year, reflecting a strong financial position and our commitment to a growing dividend. With respect to our balance sheet, we ended the quarter with $8.3 billion of total debt, $2.4 billion of total finance lease obligations, and $4.7 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 18% as of December 31, 2025. We ended the quarter well-capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2026 to be approximately $1.7 billion, which includes expenditures for turnarounds, catalysts, regulatory compliance, and joint venture investments.

About $1.4 billion of that is allocated to sustaining the business and the balance to growth projects. These 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 first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.695-1.745 million barrels per day; Midcontinent at 430,000-450,000 barrels per day; West Coast at 160,000-180,000 barrels per day; and North Atlantic at 485,000-505,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $5.17 per barrel. For the renewable diesel segment, we expect sales volumes of approximately 260 million gallons in the first quarter.

Operating expenses should be $0.72 per gallon, including $0.35 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 first quarter. Operating expenses should average $0.49 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $140 million. Total depreciation and amortization expense in the first quarter should be approximately $835 million, which includes approximately $100 million of incremental depreciation expense related to our plan to cease refining operations at our Benicia Refinery. We expect incremental depreciation related to the Benicia Refinery to be included in D&A for the first quarter and in April. First quarter earnings impact is approximately $0.25 per share based on current shares outstanding. For 2026, we expect G&A expenses to be approximately $960 million.

Lastly, our capital allocation framework remains unchanged, with a commitment to a through-cycle minimum annual payout ratio of 40%-50% of adjusted net cash provided by operating activities, and our long-term target net debt-to-cap ratio remains 20%-30%, with a minimum cash balance between $4 billion-$5 billion, with all excess free cash flow going towards shareholder returns. Thanks, Homer. That concludes our opening remarks. Before we open the call to questions, please limit each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.

Thank you. The floor is now open for questions. 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 yourself from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the Star keys. Again, that's Star one to register a question at this time. The first question is coming from Theresa Chen of Barclays. Please go ahead.

Good morning. Looking at the macro outlook, certainly we're seeing inventories building coupled with relatively high domestic utilization, as well as what seems like a precarious supply and demand setup given significant capacity slate has come online in Asia balanced against limited closures for the year. In light of these developments, how do you view the evolution of supply and demand dynamics for light products and crack spreads going forward?

Yeah, Teresa, this is Gary. Certainly, during November and December, we saw fairly significant builds in total light product inventory. It followed typical seasonal patterns, but the magnitude of the build was much larger than what we typically see. So we kind of went from below the 5-year average on total light product inventory to above the five-year average. We didn't see anything abnormal in product demand in our system. Gasoline sales in the fourth quarter were flat year-over-year. Distillate sales in our system were actually up 13%. And I would tell you that's probably more related to a change in our customer mix than anything else. But good domestic demand, our exports quarter-over-quarter were up. Exports year-over-year were up. So again, good demand in the product market. But really, what caused the inventory build is exactly what you alluded to.

We just ran very high refinery utilization. So especially in December, where you were at 95.4% utilization, very strong for that time of year. I think some of that was related to the very strong margin environment we had in November. Cooler weather allows you to push utilization rates as well. The thing that's really interesting to us is almost all that inventory build was in PADD 3. And we've always stated we like our position in PADD 3 because it allows you to clear any link to the export markets. We didn't really build any inventory during the fourth quarter. Didn't see any economic incentive to carry inventory or produce summer-grade gasoline. So we're not really sure what caused the inventory build in PADD 3.

Going forward, when you look at 2026, most of the consultant data would show similar supply-demand balances to last year, but they are assuming lower refinery utilization, refinery utilization coming back to normal levels. I think we agree with that. You've already seen utilization drop as we start into turnaround activity. As we wrap up turnarounds, I think you'd get into warmer weather, which, again, it's hard to push refinery utilization due to some overhead temperature limits. With the assumption of more normal refinery utilization, to us, it looks like demand is outpacing additional supply. Our numbers would indicate about 400,000 barrels a day in net capacity additions. We're showing about 500,000 barrels a day of total light product demand growth. So things look tight in the consultant data. There's also a lot of assumptions in the consultant data. They assume Russian refining capacity comes on, runs normally.

They assume a lot of the new capacity that's starting up runs at nameplate. Assumptions around bio and renewable diesel coming back into the market in a strong way. And then really no refinery rationalization outside of what's already been announced. So I would say our outlook is a little more bullish than what the consultants are showing just because we believe execution risk remains high on a lot of those assumptions that I just mentioned. Really difficult to get much of a read on the market thus far this year, mainly due to the weather. I can tell you that first couple of weeks in January, we're fairly soft on domestic demand. That's typically the case. Things had started to recover nicely. Last week, we were back up to around 1 million barrels a day on U.S. wholesale, but then we had the winter storm hit.

So last weekend, we saw wholesale liftings that were about 40% of the prior weekend. It's remained soft this week, but gradually recovering. Sales yesterday were about 90% of normal. Continue to see good export demand. Diesel export arb to Europe is open. Diesel exports into Latin America are economic. Good gasoline demand into Latin America. And then we don't see an arb to really send winter-grade gasoline to New York Harbor. So all of those things are constructive.

Super helpful. Thank you, Gary. Looking at the feedstock side of things with the Venezuelan crude being rerouted to the Gulf Coast, how much of this can be absorbed within your footprint over time? And can you also elaborate on how you see this impacting differentials? Without a meaningful and immediate increase in Venezuelan production itself, how do you see this equilibrating over time? And what are the implications for both Gulf Coast light-heavy diffs as well as light-heavy diffs in the Midcontinent given the related impact to WCS?

All right, Teresa, this is Gary. I'll kick that off. Obviously, having the Venezuela supply kind of back in the fold for our system is great news. The exports that are coming out of Venezuela tend to be very heavy, high sulfur, high acid, and that fits our configuration pretty well. In fact, if you look over the last 10 years, Valero has been the largest purchaser of Venezuelan heavy crude more than any other U.S. refiner. Historically, you look back, and we've ran as much as 240,000 barrels a day of Venezuelan heavy in our system. However, that was prior to the new coker project at Port Arthur that was installed in 2023. That project has substantially increased our processing capability for heavy crude. So we'd expect our Venezuelan processing capability to be substantially north of that number now.

Kind of looking at differentials, I mean, not only Venezuela, but we've had several beneficial factors that have occurred to kind of help move this market weaker. After last year with discounts fairly tight, most of these market moves tend to are making differentials increasingly favorable for refiners with high-complexity refineries such as ours. OPEC increases have announced 2.9 million since April of last year. We've seen growing sour crude production in the U.S. Gulf. It's now over 2 million barrels a day. That's up about 200,000 barrels from a year ago. We've seen a resumption of the Kirkuk exports that started in October. And we continue to see high production or growing production out of Canada that's been helpful. One other factor that's been helping discounts is freight rates have been sharply higher.

If we look at current rates compared to where we were in the fourth quarter, freight's up about 30%. So when freight goes up, since the U.S. barrel must price to clear, it's having to have wider discounts in order to allow those exports to happen. So right now, we're seeing Heavy Canadian in the Gulf Coast trading at about $11-$11.50 under Brent. That's about $4 cheaper than our Q4 average. And similarly, Mars in the Gulf has been around $5 discount to Brent. That's about a dollar kind of cheaper than we were in the fourth quarter. So all looks pretty favorable, I think, for discounts kind of heading into 2026.

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

Yeah, good morning, team. The first question, I guess this would be for you, Homer, would be around return of capital. Last year, you guys were pretty strong versus I think what market expected. Just we do get the question with the stock having done well. How aggressive you will continue to be around buying back stock, and love your perspective on that, especially as you step into the CFO seat.

Yeah, hey, Neel, good morning. I'll start. Obviously, returning excess free cash flow to our shareholders through share repurchases has been a pretty core tenet of our capital allocation framework, right, for over a decade. We've reduced our share count by over 40% since 2014. Maybe I'll just talk a little bit about the framework. It all starts with the balance sheet, right? It's in one of the best positions in the industry. If you look at our net debt-to-cap ratio at 18%, it's actually below our long-term target of 20%-30%. Our year-end cash balance was at $4.7 billion, again, towards the high end of our target range of $4-$5 billion. We don't really have any pressing need to pay down debt or build more cash. Then let's move to the discretionary uses of cash, right?

I'm not going to mention sustaining CapEx and dividend, which we obviously consider non-discretionary. So on the discretionary side, you've got growth projects, you've got acquisitions, and share repurchases, right? So starting with growth projects, we're going to be guided by our minimum return threshold, right? We're going to stay disciplined. On acquisitions, same. We have to see good strategic value and a clear and quantifiable assessment of synergies. So we're not going to just do growth projects or acquisitions just because we have excess cash. So absent those uses of cash, we're going to continue to lean into share repurchases. And if you think about share repurchases, there's always an underlying ratable part of share repurchases to meet our minimum commitment of 40%-50%. And then beyond that, we do look for opportunities to be more aggressive around share repurchases.

That's really any given period where we see weakness, particularly if our share price is weak on a relative basis to the broader sector. To your point on stock trading near all-time highs, I mean, you go back 10 years when the stock was trading around $50-$60. We've been getting that question ever since then. For what it's worth, our return on buybacks is above mid-teens over that 10-year period with where the share price is today. Frankly, I hope we keep getting the same question for the next 10 years because that means the stock is doing well.

Yeah, that's a great answer, Homer. So thank you for that perspective. The follow-up is just we are seeing heavy start to discount, particularly Western Canadian crude. And so there was a story out there that some of the folks who are marketing the Venezuelan barrels were trying to bid them in pretty tight into the Gulf Coast, maybe even move it into China. I just think from your guys' perspective, you have options for heavies, including Western Canadian down on the Gulf Coast. So if you could expand a little bit more on that specifically, as you see the go-forward for the barrels that are being marketed in, you think they're going to have to compete a little bit wider in order to compete with your alternatives?

Hey, Neel, this is Randy. I'll comment a bit on that. We're not going to comment on pricing for deals that we've done, but I'll just say that we're evaluating Venezuelan crude like we always do for all of our alternatives. We put it into the basket of alternatives, and we will purchase Venezuelan crude if it beats our alternative. So yeah, you've seen all the articles. I've read them as well. Looking forward, we've already kind of engaged with the three authorized sellers of crude, and we've purchased barrels from all three. So we anticipate the Venezuelan crude making up a pretty large part of our heavy diet as we move into February and March.

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

First, wanted to congratulate Brian on the new role of investor relations. And then also really wanted to congratulate the incoming CFO for pushing the stock price to an all-time high. Target achieved very quickly. On a more serious note, Homer, look, even when we go back four or five years for the same refining margin, what we are seeing is the cash flow profile of the company is different. You're producing more cash even if the margin was the same four or five years ago. Can you help us understand the dynamics over there? What's been behind this transition to generate the ability to generate more cash with the same refining margin?

Yeah, hey, Manav. So Lane's talked about this in the past, but it's really a result of a number of things. And it all starts with being a good operator, having discipline around capital investments, and then a strong balance sheet, which ultimately all translate to higher cash flow and higher shareholder return. So starting with operations, we've obviously worked really hard to manage costs and our reliability over the years. And you can see that with the record throughput and mechanical availability this past year. And then we've also been very disciplined around growth investments. Obviously, you know our minimum return threshold, which effectively ensures you have a good return when things are good, but also hopefully protects us with a return that's well above our cost of capital, even in kind of a downside scenario.

You can see that if you look at our return on equity or return on invested capital over the last 5 or 10 years, that's in the mid-teens or higher number. And again, keep in mind that denominator for that return on equity or return on invested capital includes all capital, right, including sustaining CapEx. And then also generally on capital, we have been trending a little bit lower in recent years, which just frees up more free cash flow for shareholder returns. Lastly, I mean, the balance sheet obviously plays a strong role in that, both in terms of we've got lower debt and higher cash balance. So at the margin, you have lower interest expense, but then higher interest income as well. But really, more importantly, just having a strong balance sheet gives you much more flexibility with respect to shareholder returns.

Lastly, obviously on a per-share basis, share repurchases have helped a lot as well.

All very good points. My quick follow-up here is very good improvement in renewable diesel. I know there were a few quarters where the industry struggled. You did much better than the industry, but the industry was struggling. We're finally seeing the light at the end of this tunnel, hopefully RVO and then all those policies will become clear. And do you expect generally a renewable diesel to deliver better earnings in 2026 versus 2025? Primarily a function of more maybe policy clarity if you could talk about that.

Yeah, hey, Manav, this is Eric. You're exactly right. We're still waiting on final policy guidance on the RVO and PTC. And so if you contrast the first half of 2025 being the transition to PTC and everyone trying to understand it, we were the first and perhaps maybe the only company that has really figured out how to capture the PTC. So the second half of 2025 was getting into full PTC capture, getting into full SAF commercialization. And between that differentiation, our ability to capture the PTC and the overall margins tightening in renewable diesel allowed us to outcompete a lot of our competitors. And as we have started 2026, there's a lot of capacity offline. There's a lot of players that are now sitting out waiting for guidance to get finalized before they re-enter the market.

That has caused fat prices to really level off and even drop throughout the fourth quarter and into this first quarter. So what I see in 2026 is policy should be a tailwind. The expectation is it should come out favorably for renewables. We do see that there's a lot of talk of tariffs continue to be a pretty strong headwind, but we'll see what the Supreme Court comes out with. And so I think you're going to see 2026 starting off more like the second half of 2025. And so that would indicate a stronger year in 2026 versus 2025.

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

Hey, good morning, everybody. I'm sure Brian has already told you about my family connection, but welcome, Brian. Guys, I wonder if I could just ask two quick ones. First of all, on all the dynamics of heavy oil in the Gulf Coast, there's obviously a lot of complexities across your system. Mexico looks like it's now running a little better, so less imports or less exports rather from there. WCS has TMX. And then, of course, there's Venezuela. And my question really is about your coker utilization and the volume of your heavy runs, where that can get to, not the crude utilization, but where you can actually get your throughput to. And my specific question is, 10 years ago, 15 years ago, you were running about 1.3 million barrels a day of advantage crude, including fuel oil. You've added the coker. You're less than a million today.

Hey, yeah. So hey, Doug, it's Lane. I'll answer this one. If you really look at what happened, we did sort of when we added the coker, because of the dynamics you're talking about in terms of heavy availability, what we really did is we incremented medium and light crude with some heavy actually ramping up into higher rates to ensure that our coker availability, our coker sort of utilization was where we felt like it needed to be to meet FID. We're also purchasing outside resids. So we're doing all that. I think what you can expect is you get more available from Venezuela, more available from Canada. You'll see us actually fill the coker up sooner with that crude diet.

We'll see on an incremental basis whether we actually increase crude rates or actually lower them depending on how incremental crude economics because we believe it'll be a driver to fill the coker with heavy.

Lane, is it possible to get a utilization rate on your coker capacity today and where it could get to, or is that too granular?

I don't know if we've ever really been public with coker utilization. In fact, I don't think we even have it in front of us. But we normally, just from a signaling perspective, most of the time, we optimize the crude diet into sort of the way you would do it. And then we purchase outside feed or internal resid feed to make sure that that coker is full most of the time.

All right. That's helpful, guys. My follow-up is actually on one of Manav's questions about the RVO and RIN prices are obviously spiked here pretty dramatically since the start of the year. I'm trying to understand how should we think? I don't know if there is such a thing as mid-cycle earnings, but at today's RIN price, obviously we're up around the $1, I think we're at $1.20 or something today per gallon. What do you think the mid-cycle earnings capacity of DGD is, or maybe free cash flow, whichever one you prefer to lean on? And I'll leave it there. Thanks.

Yeah, that's not really a question that you can easily come up with an answer on about mid-cycle for RINs. What I would say is you've kind of been a new framework with the PTC. So the previous 10 years of DGD was on the blender's tax credit. So everyone gets $1 cash from the government for every gallon that you produce. Now we're into a regime where it is dependent on your CI. It's dependent on your income tax because it's now an income tax credit. So you're into a different, just an overall different framework. Now, RINs have been underlying this will be a part of this in the past as it will, as it is going forward.

I think as we think about where this all goes, what the government has suggested as an obligation range of 5.2-5.6 billion gallons for 2026 and 2027 is well above domestic production capability. So if you see that and with the combination of tariffs on foreign feedstocks and the elimination of credits for foreign imports, the entire compliance, essentially you're raising the obligation while also making it harder to generate. That all points to a higher D4 RIN price, especially as you draw the bank down, which a 5.2-5.6 obligation number would certainly do. And so what I would say is it's not really trying to think about what a mid-cycle it is, more just saying that there's a good chance D4 RINs are going to go up.

So then the next question is, does fat prices just follow that up and keep overall RD margins tight? Or do you see from a competitive standpoint, going back to the PTC, that low CI and the ability to run waste oils over veg oils is still going to have an advantage in this new framework of PTC? So all of that just really saying 2026 is going to likely look better than 2025 for the segment. Then it particularly looks better for those that can export into advantage markets into Canada and Europe and the UK, those that operate just like refining in the most efficient capacity in the Gulf Coast, and then those that can run waste oils over veg oils.

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

Lane, I don't know whether you guys will be willing to share. That's a, as usual, every several years that we have the labor contract being negotiated, Marathon is heading that with the USW. And can you tell us that which of your refineries is currently under that contract? So in other words, that if that's in case if there's any strike, I'm sure that you guys are well-prepared management will be able to take care of it for a period of time. But which refinery or what percent of your capacity is actually will be impacted? Second question is that I think that has been asked previously. If we look back in your utilization rate, historically, I think on a four-year basis that your maximum may be doing somewhere in the 94%-95%.

Do you believe, given you've been it looks like that has been done a phenomenal job in operating your facility better and better? Do you think that now, on a maximum full-cycle basis, that you would be able to do better than that? Or that, I mean, that the entire curve has been shifted up, what I mean, compared to maybe 10 years ago, what, 1% or 2%? Is there anything that you can help to quantify it?

Hey, Paul, Lane, I'll take a stab at the first one. I just, yeah, so your instincts were correct. We're not really going to disclose exactly which one of our sites and everything are under USW and some of the other maybe unions that are out there. What I will say, one of the advantages that Valero has versus our competitors in that space, however you think about it, is we're less unionized directionally than a lot of the other people in the space. I don't buy everybody, but directionally, that's true. And on the second one, I guess it's.

Yeah. So I think, Paul, what I'd tell you is we obviously had a record year in terms of mechanical availability last year. With better mechanical availability, you would expect to see better refinery utilization. To try to quantify that would be very difficult.

Hey, Gary, do you think that the whole industry is getting better?

It's a good question. I think a lot of what you saw in the fourth quarter was very strong margins and moderate temperatures. And so that allows you to kind of push refinery hardware a little bit harder than you normally could. I think it'll come back off. I don't think what we saw in December is sustainable, but everyone is certainly trying to drive up mechanical availability as we have.

And that you're talking about the weather, do you guys have any noticeable downtime from the winter? That's my last question. Thank you.

Yeah. Yeah, Paul, we really fared the winter storm pretty well. We had a few nuisance-type heater trips, but nothing material. I think most of what we saw was really things external to the refinery, some interruptions in hydrogen steam hitting up against product containment-type limits. But if you look at our guidance, I would tell you there was nothing material that related to the winter storm that's going to impact the quarter.

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

Good, thanks. Maybe one on the West Coast, if you could just talk a little bit about West Coast refining. A couple of things, maybe profitability was a little weaker in the quarter. Can you maybe talk about what some of the drivers were there? And then can you maybe walk us through the timeline of the coming shutdown of Benicia and how you're thinking about West Coast dynamics for 2026?

Yes, I'll start on the first. Yeah, our capture rates were a little down on the West Coast. Some of that is to do with the fact that gasoline relative to diesel gasoline was pretty weak relative to diesel. As we've talked about, especially our Benicia Refinery has a really strong gasoline yield. And so it tends to lower our capture rates. The other thing that hurt us is there was a retroactive tariff adjustment on one of the pipelines we utilize on the West Coast, and all those charges hit during the fourth quarter. So those are the two big things that impacted our capture rates in the fourth quarter on the West Coast.

This is Rich Walsh. I'll try to answer on the timeline there. In terms of the Benicia idling, we're executing our plan to safely idle it, the refinery operating units that is. It's a well-planned out and phased process. In February, you saw, I'm sure you saw our most recent announcement, we will be idling the process units because they have some mandatory inspection requirements that are kicking in then. So we'll be pulling those offline. But we will be continuing to produce fuel as we work down the inventory through this process. As we've shared with the governor and the CEC, we are going to be importing some gasoline and/or gasoline blend components over the near term. We remain committed to our contractual obligations out there to meet the supply obligations that we have.

We're working cooperatively with state officials, the CEC, and the governor on our plans. We've kept them fully informed, and they're aware of our supplemental supply commitments to the Bay Area. I think that's pretty much where we are. Then in terms of Wilmington, it's normal operations, and we'll continue to supply the California market out of Wilmington.

Great. Thank you. And then maybe just maybe one follow-up for you, Eric, on the RVO stuff. Any thoughts in terms of what you're hearing on timing or any of the items which are kind of debated out there, whether it's SREs or reallocations or penalties for foreign feeds or products, directionally, what you're hearing on those things?

Yeah, that's really kind of a government question. I'm going to let Rich answer that.

Yeah. I mean, look, UK has got a big challenge on dealing with the RVO right now and the SREs. And I think the administration is starting to recognize how now that all of this is getting caught up with these SREs, they've really gotten out of hand. If you look at EPA, they sort of defaulted to this outdated DOE process that the government accounting office has already said was a flawed process, and both EPA and DOE had acknowledged that previously. And this matrix is so out of date, it doesn't even account for the shale revolution and the domestic production, which has completely transformed the U.S. energy market. So it's a really flawed SRE basis that's out there.

In terms of solutions, I mean, I think there is a legislative proposal out there that's a compromise that's supported by API, by ag interests, by retail trades and most refiners that would allow a process to go forward that would kind of help correct all of this and get us kind of realigned and supporting the RFS. But there are a small number of conglomerate, so-called small refiners that are out there that are having a windfall on these SREs, and they're kind of holding it up. So that's where we think this stuff is going to have to be worked out. It's a challenge for the agency that kind of gotten into a fix with overissuing these SREs.

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

Glad to hear, Brian, that you got the job because of your close family relationship to Doug Leggett. But I joke. Hey, guys.

Just on demand and supply, at the moment, obviously, we're seeing oil through $70. Would you say that's related to the sanctioned shadow fleet being shut down effectively or more shut down than it has been? I'm just wondering. It's a big surprise, I think, to all of us. There's obviously the demand side of the equation. I was just wondering what your perspective is on U.S. oil demand right now in this storm because we're seeing some big numbers from some of the northeastern generators, I mean, 300,000+ type daily use of oil to generate power. You didn't seem to really highlight that in your very complete comments so far. I just wondered if you're seeing a big impact from this storm in terms of the demand side of the equation, which might help to explain why we're at $70.

The overall question is, how come we've gone through 70 here at a time seasonally of weak oil prices? Thanks.

Yeah, Paul, I'll just touch on the flat price. I mean, I think what we're seeing right now with the geopolitical wrangling going on in Iran, I think, has put quite a bit of geopolitical risk factor on top of flat price. Plus, you had the winter storm take off some oil production in the shale patch, in addition to the continued issues with the CPC and Tengiz over in Kazakhstan that had quite a bit of oil offline. So I think all those are leading to some short-term tightness, plus the geopolitical factor that's kind of running up oil here in the short term.

Yeah. In terms of heating oil demand, I think a lot of that is just where we have a strong wholesale presence. We're not really strong in the heating oil markets. In markets like Boston, where we do have a presence, we have seen a significant uplift in diesel demand as a result of heating oil. And then the rest of it for us, a strong incentive to shift to New York Harbor, which is, again, tied to heating oil demand.

Great. Thanks. If I could ask a follow-up, Lane, is there a way that you could see more investment as you shut down California? I'm wondering how your exposure to California is going to change if you're going to kind of effectively exit that market or if you'll have access to it through other means. And secondly, whether or not you would consider perhaps with more heavy oil coming back on the market with the decline of potential, certainly decline of U.S. light sweet production, whether there might be more CapEx to be undertaken.

Hey, Paul, Lane, I don't think you'll see our CapEx increase with respect to the West Coast, as a matter of fact. I'd have to go back and look how long we've sort of obviously, what we've done out there is maintain our sustaining capital for all these years with respect to the West Coast because we didn't see a market that we were going to grow the capacity to produce into it. So what you're actually going to see is when we shut Benicia down, our sustaining CapEx should fall. I'm going to pick a number, somewhere around $150 million or so. Our sustaining capital will actually fall. With respect to how we see California is still a very it's a challenge to operate out there. We'll continue to operate Wilmington. It's a good asset and a good market.

It has its challenges with respect to regulatory capital at the end of the decade, and that's when we'll sort of make our decision on how our presence on the West Coast will, how it'll be, so.

Anything on incremental spending on a heavier slate going forward, potentially, Lane?

We will definitely look at that in terms of our strategic cap. We are looking at that. We have other things that we have in our gated process. We don't necessarily—our tendency as a company is to talk about projects as we FID them, not as we are studying them. But we have a pretty good position as it is, so we want to make sure that we don't hurt that position. But clearly, as there's more available in the heavy oil market and we hit these constraints again, we'll study. We'll see what it would take to do. It'll probably still fit into the small CapEx. We're not going to do a great coker expansion or anything like that. That's not a foreseeable future.

Thank you. The next question is coming from Sam Margolin of Wells Fargo. Please go ahead.

Hey, morning. Thanks for the question. Revisiting CapEx, growth CapEx is pretty moderated. I think you've explained why. Just drilling into it, how much is inflation a factor with the gated process and returns? And if it is a big factor, what do you think that means for sort of buy versus build decision-making to the extent that you're interested in growth?

Valero Energy (VLO) Q4 2025 Earnings Call Transcript

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