Homer Bhullar :

Good morning, everyone, and welcome to Valero Energy Corporation's second quarter 2024 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; and Gary Simmons, our Executive Vice President and COO and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Lane for opening remarks.

Homer Bhullar:

Thanks, Lane. For the second quarter of 2024, net income attributable to Valero stockholders was $880 million or $2.71 per share compared to $1.9 billion or $5.40 per share for the second quarter of 2023. The Refining segment reported $1.2 billion of operating income for the second quarter of 2024 compared to $2.4 billion for the second quarter of 2023. Refining throughput volumes in the second quarter of 2024 averaged 3 million barrels per day. Throughput capacity utilization was 94% in the second quarter of 2024. Refining cash operating expenses were $4.45 per barrel in the second quarter of 2024. Renewable Diesel segment operating income was $112 million for the second quarter of 2024 compared to $440 million for the second quarter of 2023. The renewable diesel sales volumes averaged 3.5 million gallons per day in the second quarter of 2024, which was 908,000 gallons per day lower than the second quarter of 2023. Operating income was lower than the second quarter of 2023, due to lower sales volumes resulting from planned maintenance activities and lower renewable diesel margin in the second quarter of 2024. The Ethanol segment reported $105 million of operating income for the second quarter of 2024 compared to $127 million for the second quarter of 2023. Ethanol production volumes averaged 4.5 million gallons per day in the second quarter of 2024, which was 31,000 gallons per day higher than the second quarter of 2023. For the second quarter of 2024, G&A expenses were $203 million, net interest expense was $140 million, depreciation and amortization expense of $696 million and income tax expense was $277 million. The effective tax rate was 23%. Net cash provided by operating activities was $2.5 billion in the second quarter of 2024. Included in this amount was a $789 million favorable change in working capital and $83 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD. Excluding these items, adjusted net cash provided by operating activities was $1.6 billion in the second quarter of 2024. Regarding investing activities, we made $420 million of capital investments in the second quarter of 2024, of which $329 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 other joint venture member share of DGD and other variable interest entities, capital investments attributable to Valero were $360 million in the second quarter of 2024. Moving to financing activities, we returned $1.4 billion to our stockholders in the second quarter of 2024, of which $347 million was paid as dividends and $1 billion was for the purchase of approximately 6.6 million shares of common stock, resulting in a payout ratio of 87% for the quarter. Year-to-date, we have returned $2.8 billion to our stockholders in the form of dividends and buybacks, resulting in a payout ratio of 80%, well above our minimum commitment of 40% to 50%. With respect to our balance sheet, we ended the quarter with $8.4 billion of total debt, $2.4 billion of finance lease obligations and $5.2 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was 16% as of June 30, 2024. And we ended the quarter well capitalized with $5.3 billion of available liquidity, excluding cash. Turning to guidance. We still expect capital investments attributable to Valero for 2024 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts regulatory compliance and joint venture investments. About $1.6 billion of that is allocated to sustaining the business and the balance to growth with approximately half of the growth capital towards our low carbon fuels businesses and half towards refining projects. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges

John Royall :

One of my questions were on the refining macro side and more specifically, your views on supply and demand. The U.S. system ran pretty hard through 2Q. We built some inventories on both the gasoline and the diesel side. What are you seeing on the demand side in both the U.S. and globally? And how do you view the overall supply/demand balance today?

John Royall :

And then my second question is on capital returns. You had another very strong quarter in this quarter, I think you're above 80% of CFO. How do you think about the cadence on the buyback going forward from here? And any thought on leading into the balance sheet for capital returns?

Homer Bhullar :

Sure. So, John, we haven't really had to lean into the balance sheet for shareholder returns. I mean, in fact, if you look back to 2020, we've been able to fund all of our uses of cash, including over $6.5 billion of capital investments. We've paid down over $4 billion of debt and over $17 billion of shareholder returns over that period all through cash flow from operations. In fact, we've actually built cash since 2020. So I think consistent with what we've been guiding to, given the strength in our balance sheet and our current cash position, we continue to lean into buybacks with a payout ratio at 87% for the second quarter and 80% year-to-date. Again, all funded within cash flow despite a lower margin environment. So I think looking forward in periods where the balance sheet is strong as it is now, we've got sustaining CapEx, the dividend and strategic CapEx covered, you can reasonably think about 40% to 50% as a floor and continue to expect any excess free cash flow go towards share buybacks.

Douglas Leggate :

Gary, I appreciate all your comments about the macro, but I'm afraid I'm going to ask another one, if you don't mind. Everything you've said makes an enormous amount of sense except for the fact that it seems that globally on a net basis, we're now back to a net surplus in terms of refinery additions compared to right before COVID. And obviously, Dangote is part of that, but we've had whiting come back online and utilization it seems it's now running pretty well. So I'm just curious as to how you think that cleans up. Do we need another turnaround capital event, like a turnaround cycle to see some of those closures? Or do you see it differently?

Douglas Leggate :

My follow-up is kind of related to that because, I mean, you guys are -- there's no question you guys are and will probably continue to be the cost leader in terms of your system, best-in-class in the U.S. for sure. The issue we're trying to figure out is where the vulnerabilities are across the U.S. in terms of the marginal refinery. And I guess for you guys, we're curious what's going on in the West Coast because just last week, we had the lowest margin since COVID on the West Coast and Benicia is obviously out there. We thought it was going to do better because of TMX. So can you maybe help us understand what is the role of Benicia in the portfolio and what do you see in the West Coast dynamics currently?

Gary Simmons :

Yes. The only thing I'd add to that is we did have the view that with some of the refinery conversions to make renewable fuels that you would see, especially gasoline pretty tight. But if you look from April to the end of June, imports -- gasoline imports into the West Coast were up 70,000 barrels a day. And I think that, combined with a little softer demand is why you're seeing that margin environment on the West Coast that we're seeing today. As far as TMX, TMX started up beginning of May. They didn't load the first cargo out until the end of May. We didn't load our first cargo out until June. So really, any impact you're going to see from TMX wasn't reflected in our second quarter results. You won't start to see that until third quarter.

Roger Read :

Maybe you take a slightly different direction here. Policy wise, at the end of June, the Supreme Court took out Chevron deference and there's a lot of ways to interpret that and some of the other things going on politically with the election. But I was just curious if you had any thoughts about -- on the policy front on that, I guess, you call it judicial front, how that might affect any parts as we think about some of the CAFE standard stuff and then has been mentioned the challenges in getting permits to do things on the expansion side?

Roger Read :

And yes, it is one of those types of topics. So the only follow-up we really had on that, and I think you kind of answered it as the timing to have impacts of this could be like, what the next 12 to 24 months? Or does it take longer?

Operator:

Our next question is from Ryan Todd with Piper Sandler.

Greg Bram:

Ryan, this is Greg. I'll talk about our system. So you do see that our throughput guidance considers planned maintenance activity we have in the quarter. So particularly if you take a look at like the North Atlantic, you see that there. Otherwise, I would just say for our system, we're optimizing our refineries in light of these market conditions, just like we always do. So, some of that might be reflected in the guidance as well. But you can definitely see where the planned maintenance activity is having an impact.

Lane Riggs :

This is Lane. I think if you sort of listen to Gary's opening comments and you think about our -- what we have said is that we do believe going forward, you're going to have a higher margin environment. You're seeing -- we're seeing refinery make cuts what at least we would have historically thought was a mid-cycle and so that -- which is an interesting thing to say, well, there are refineries out there that are seeing marginal economics in the -- historically mid-cycle economic environment. And so that would tell you, we don't know where the lows are. You're telling let's indicate that the call on refining is because of that, there's some thrown that have -- that are cutting in this space. So again, it just reinforces our view that you have a higher margin for our capital and higher mid-cycle going forward.

Manav Gupta :

My first question is your outlook on the Gulf Coast heavy sour differential looks like OPEC will start adding volumes somewhere in the fourth quarter and then continue to do that in 2025, and then also there is a bigger refining asset in that area, which uses a lot of that crude, which will be hopefully closing down in early 2025. So your outlook -- medium-term outlook for the heavy sour differential on the Gulf Coast.

Manav Gupta :

My follow-up here is, as you're approaching your completion on the SAF unit, are there any preliminary estimates we should think about how much of an uplift could this change going from early to SAF provide to you guys?

Operator:

Our next question is from Theresa Chen with Barclays.

Gary Simmons :

Well, I guess I'd just say our wholesale team has done a great job for us on growing our market share. And then some of that has also been due to some of the refinery rationalization that took place, especially during the COVID period. It's allowed us to grow our market share as well.

Eric Fisher :

Yes, that's something everyone is trying to figure out and it's a really difficult dart to throw these days. I think one of the things we look at is, the RIN market still looks oversupplied to us. So as we kind of get into the back end of '24, it looks like the RIN market is long, the California LCFS market will remain long and therefore, we think with fat prices starting to increase, we see compression in RD margins in the back half of '24. The policy things that are coming up, LCFS might expand with California. They're still saying that's going to be a 2025 change. The RIN update for 2026 got pushed to March of '25. But with all the expectations that Ag has on the RFS volumes, we expect that will probably be some sort of increase. So I think longer term in sort of the next one to two years, we see a lot of tailwind for DGD in terms of credit prices. Specific to our platform, we are obviously diversifying into SAF. That's going to be a diversification away from RD with -- that includes a premium to RD. So that looks pretty strong. And then the other thing that will be interesting because this is being looked at now is, are we going to have a BTC or PTC transition January 1. And as we've said in the past, the RIN and the BTC have a relationship that previously, when we discussed the BTC going away, we expected the RIN to increase to keep the biodiesel producer at breakeven. So when you think about a BTC to PTC transition where the PTC is less than $1, there is some view that the RIN will have to pick up the difference in order to keep the biodiesel blender breakeven. So you have a little bit of a discussion of the market and the credits look long but the relationship between BTC, PTC and the RIN has always been somewhat of a factor of rebalancing the market. How fast that happens, how soon that happens, the timing of that, given the elections, those are all kind of up in the air. But I think structurally, as you look forward, all of this looks pretty good for DGD.

Paul Cheng :

I think this is for Gary. Gary, can I go back into your comment. First low in May and so now just two months. So where you can see, do you think the impact on the West Coast market from the TMX is now fully retracted in the marketplace? Or the thing over the several months that we do have solution indication to the crude defense in that market? Secondly, maybe this is either for Gary or for Lane. As the market normalizes, how does it impact the way how your refining operations run in terms of the sustainable maximum run rate crude yield or product yield, whatever that you can give some comments that would be great.

Lane Riggs:

I'll take a shot at the second one. Paul, this is Lane. I don't really see as the world sort of settled on some other places that impacts our operations. We always take signals from the market. We focus on being reliable. We focus on execution. We don't move turnarounds and do things like that based on whether we think the markets good now, not later. Our idea is operational excellence means that we wake up every day, we try to -- where we will execute in a way there were the best operator that we can be, which we think we are the best operator out there. And so we don't really profoundly see any change based on necessarily some sort of different refining outlook.

Joseph Laetsch :

So on the refining side and on the export side, specifically, would you mind just giving us an update on Mexico? And if I remember right, I think there was a new terminal opening there this year as well.

Joseph Laetsch :

And then shifting over to RD. So I know you talked about this a little bit earlier and feedstock costs have been higher over the past couple of months, but could you just talk about a little bit more about what you're seeing on the feedstock cost side as well as availability here with some of the new start-ups?

Operator:

Our next question is from Neil Mehta with Goldman Sachs.

Greg Bram:

Neil, this is Greg. So we still see good value in coking margins. Gary talked about where the heavy sour crude market has been. That's with our coker online and with the industry running the way it has. So I don't think that we see something that's a big step change going forward. As Gary mentioned, as you put -- as you get some more medium sour, heavy crude into the market later this year that should enhance that value. But right now, it's still a strong opportunity for us still beats our other modes of operation and something we're looking to maximize.

Gary Simmons :

Neil, this is Gary. We don't have a lot of visibility into the markets in the Far East. But I would tell you, certainly, what you read is in China, especially diesel demand is down. We see as much as 10% a lot less construction activity there. But for the most part, it looks like they've adjusted refinery runs to say somewhat balanced on exports. Now we would say exports are up slightly. But for the most part, they've adjusted refinery runs to balance demand, and we haven't seen a significant step change in their exports.

Jason Gabelman :

I wanted to go back to the wholesale channel growth. And it's been pretty consistent over the past few years. And I'm wondering, if you can provide some sort of earnings estimate in terms of an uplift from selling through that channel relative to maybe some pre-COVID period or other baseline you have available and if you expect that growth to continue?

Jason Gabelman :

Can you provide on a volumetric basis, how much it's grown and how much more you think you could push to that channel?

Homer Bhullar :

Jason, there's a page, I think Page 24 in the deck, which goes all the way back to 2012 for more color.

Greg Bram:

Yes, Jason, this is Greg. You're right. That was a headwind. I don't know if I have the exact amount. And that will come and go over time, certainly was working against us in the second quarter.

Matthew Blair :

Maybe just sticking on capture. I think it makes sense that your capture was lower quarter-over-quarter just due to those challenges in the co-products, at the same time, I believe that the Q2 capture was the lowest absolute number in like five or year years. So has anything changed structurally on your capture compared to even just like last year?

Matthew Blair :

And then on the ethanol side, if I could ask, how sustainable do you think this recent uptick in ethanol margins is? And also, is there an update on the Summit carbon capture project? When do you expect that to start up and benefit your ethanol plants?

Operator:

We have reached the end of our question-and-answer session. I would like to turn the conference back over to Homer for closing remarks.

Operator:

Thank you. This will conclude today's conference. You may disconnect your lines at this time and thank you for your participation.

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2024 Earnings Conference Call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team.

Operator:

[Operator Instructions] Today's first question is coming from Theresa Chen of Barclays.

Gary Simmons:

It's Gary. I can -- I'll give you some insight as to what we're seeing in the market today and then some thoughts on your final question. Overall, we continue to see strong light product demand. In our system, we've seen gasoline sales trending at levels equal to last year. Diesel sales in our system are actually trending about 2% higher than last year.

Theresa Chen:

Really helpful. And maybe following up on the point about Russia, and I appreciate you going through the dynamics on the diesel exports and such. Maybe looking at the naptha side of things. So if the naptha export starts to fall off as well, what does that imply for octane economics? And in light of maybe more naphtha from some of the new refining capacity added, like what is the net impact and the translation to gasoline margins as a result?

Neil Mehta:

Another really strong quarter. And I wanted to ask about the cash flow payout as you're well above the numbers that you've targeted as the floor and so I guess the $1 billion of repurchase level, do we view that as a sustainable run rate? And how do you think about how investors should anchor to a payout guidance?

Homer Bhullar:

Yes, Neil, I think given the strength of our balance sheet in the first quarter and the fact that we're not really looking to build more cash, we had a pretty strong payout at 74%. And you'll remember, last quarter was 73%, which ended the year at 60%. So I think you can think of the 40% to 50% range as a long-term through-cycle commitment.

Neil Mehta:

Okay. That's helpful, Homer. And then follow-up is just on DGD. There was a pull forward of the SAF projects. So it looks like project is tracking well for '24 start-up. So just how -- once it comes into service, what's the back of the envelope of how we should think about the incremental economics? And what type of premium margins do you think you could sustain on SAF barrels?

Roger Read:

Yes. Probably to come back on some of the macro stuff here. Crude differentials, we've got some, I guess, discipline out of OPEC, we've got TMX starting up, I guess, almost any day now, we have some tightness from some other places that typically have exported heavier crudes to the Gulf Coast. So just curious what you're seeing on the crude, call it, availability front and expectations on differentials?

Gary Simmons:

No. I think a lot of that gets driven by availability of intermediate feedstocks, VGO. In a tight VGO market, then you're kind of forced more to swing either gasoline or diesel. So far, availability of VGO has been okay. We've been able to fill all the conversion units, but we'll have to see how that goes moving forward.

Manav Gupta:

Congrats on a strong quarter again, guys. My first question here is the bear thesis on refining somewhere was [indiscernible] and it looks like it's not played out these assets from what we read and hear, one of them doesn't have enough hydrogen, the other doesn't even have an FCC. So most likely will not be providing products to the market, maybe even year-end 2024.

Gary Simmons:

Yes. So we see it exactly like you've described. This year was the year where you had kind of a peak in terms of new capacity additions. And then from this point forward, you get to where global petroleum demand outpaces new refinery capacity additions significantly, and we see several years of tightness.

Lane Riggs:

Manav, it's Lane. That's what I was going to say. But it speaks to the culture. Our culture is very much about high discipline, high accountability and teamwork. We make sure we get the right people into the right jobs and hold them accountable and making sure that they're -- and when I say the right people, they have to be people who are, a, competent; and b, they're willing to work with the other team members who may not necessarily be under them or adjacent to them and ultimately working on behalf of Valero.

Operator:

The next question is coming from Ryan Todd of Piper Sandler.

Ryan Todd:

And that's probably something that's happening on a broader sets across the system with general global crude mix being lighter, right?

Ryan Todd:

Maybe switching gears to Diamond Green Diesel. I mean as you think about the broader -- obviously, we've been through a soft spot here on renewable diesel margin with RINs and LCFS pricing low. As you think about the outlook into the back part of this year and into 2025, can you maybe walk through how you view some of the moving pieces that could tighten up that market and improve kind of the relative profitability of whether it's renewable diesel or then eventually SAF in 2025?

Operator:

The next question is coming from John Royall of JPMorgan.

Greg Bram:

John, this is Greg Bram. I'll talk about our turnaround activity. Particularly, in the first quarter, we had a pretty heavy turnaround load. You can really see that when you look at our throughput, particularly the Gulf Coast through being much lower. It's just reflective of the work that we had going on.

Joseph Laetsch:

Congrats on a strong quarter. So I wanted to go back to SAF. Are you seeing enough demand from customers to potentially support an additional project? And then if so, would this -- would any potential announcement come after the first facility is online? Just trying to think about timing overall.

Gary Simmons:

Yes. So I think my comment there, when you have cracking margins in Singapore negative and you have hydroskimming margins in Europe negative, it kind of tells you we've hit a floor, we need the capacity to run and I think you'll see margins start to tick back up.

Paul Cheng:

The first question, I think, is either for Gary or for Lane. Peer mix start up, and so that's going to bring the WCS, which is mostly the main mix in [indiscernible] heavy oil with really heavy [indiscernible] barrels and [indiscernible]. So when that happens, will your system be able to convert all your -- if the price is right, can your system convert all your heavy intake and the medium intake into using a some form of combination of WCS plus some light barrel or that is not as simple? And also whether the industry will be able to, say, eliminate all the import from the heavy barrel from, say, [indiscernible] from the Middle East, replacing with WCS? That's the first question.

Paul Cheng:

Okay. And second question then, Gary, can you give us some maybe your [ comments ] that what you see in the Mexican market for both gasoline and diesel?

Paul Cheng:

Gary, do you have an export number you can share in the first quarter.

Operator:

The next question is coming from Matthew Blair of Tudor, Pickering, Holt.

Lane Riggs:

This is Lane. Not really. I mean we always look at everything. I mean if you look at the most prompt sort of big deal that's out there [indiscernible] we sorted as a corporation decided not to engage in that. For whatever reason, whoever the successful buyer they can sort everything out wants to liquidate some of the assets, we'll certainly look at them at that time.

Operator:

The next question is coming from Jason Gabelman of TD Cowen.

Gary Simmons:

Yes. So this is Gary. I would tell you, in the first quarter, we saw a little lower demand, at least in our system, California for gasoline, which I think was related to weather. We've seen demand kind of return to normal patterns. And it's very difficult to just speculate and put barrels on the water to import the California market.

Jason Gabelman:

Got it. And then my second question, just going back to the commentary around the global lighting crude slate. And you had previously made a comment that crude gravity over the past few years has gone up 3 to 4 points and that's maybe reduced global capacity available by 3 to 4 percentage points. Can you just comment on that dynamic?

Greg Bram:

I don't have any rules of thumb either.

Homer Bhullar:

Thank you, Donna. Appreciate everyone joining us. Obviously, please feel free to contact the IR team if you have any follow-up questions. Thank you, everyone, and have a great day.

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation's fourth quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now, I'll turn the call over to Lane for opening remarks.

Homer Bhullar:

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

John Royall:

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

John Royall:

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

Homer Bhullar:

Thanks, Jason. Yes, John, I mean our approach to shareholder returns is driven by our annual target of 40% to 50% of adjusted net cash from operations. And obviously, that includes the dividend, which we consider non-discretionary and buybacks, which are considered the flywheel supplementing our dividend to hit our target. And given the strength in our balance sheet in the fourth quarter, as we highlighted, we had a 73% payout which resulted in a 60% payout for the year. And as you touched on, since 2014, we've regularly paid above our target. And in fact, the average payout for the 5 years leading into COVID was around 57%. So I think in short and periods when the balance sheet is strong as it is now and sustaining CapEx, the dividend and strategic CapEx is covered. You can reasonably think of our 40% to 50% target as a floor and expect any excess cash to go towards buybacks.

Operator:

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

Gary Simmons:

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

Gary Simmons:

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

Operator:

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

Lane Riggs:

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

Greg Bram:

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

Neil Mehta:

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

Doug Leggate:

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

Doug Leggate:

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

Homer Bhullar:

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

Operator:

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

Eric Fisher:

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

Gary Simmons:

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

Manav Gupta:

Thanks, guys.

Sam Margolin:

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

Sam Margolin:

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

Sam Margolin:

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

Sam Margolin:

Awesome. Thank you so much.

Paul Sansky:

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

Paul Sansky:

Venezuela. Venezuela.

Paul Sansky:

Mexico refineries, though.

Paul Sankey:

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

Paul Sankey:

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

Operator:

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

Gary Simmons:

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

Eric Fisher:

Yes. I would say the outlook for renewable diesel, it is difficult to predict exactly how it will play out because you do have additional capacity coming online and into fixed credit banks for both RINs and LCFS that would naturally say that those credit value should come down with additional capacity, which would narrow RD margins. That being said, we also see that feedstock prices continue to come down, both waste oil and veg oil. So then you get into the waste oils will always structurally have a lower CI advantage over veg oil. So where veg oils will be long, they still won't be competitive to waste oils into compliance markets. So it goes back to the core of the DGD business, which is a low-cost producer waste oils, access to markets besides California. And so, we still see that we'll be competitively advantaged, both from an OpEx and feedstock standpoint. But overall, the outlook, I would say, is we expect that credit prices will continue to narrow. And it's a question of how feedstock prices we'll keep up with that. And so -- and then the last thing, besides diversifying sales away from California is obviously with our project, we'll be diversifying into SAF, which takes some of our product out of this RD market. So we think both of those things make us still the most competitive and advantaged platform in R&D, even in a tightening market.

Eric Fisher:

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

Operator:

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

Greg Bram:

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

Ryan Todd:

Great. Thank you. And then maybe just a follow-up question on capital spend and growth capital spend. I appreciate it, Homer, you gave a little bit of detail there in terms of some of the things that are competing for the wedge of growth capital within your budget. I mean most of your larger project-driven work is either finished recently or you've got the SAF project, which isn't really all that large. But as you look forward on the horizon, are there any other meaningful environmental or regulatory-driven capital things that we should be keeping our eyes on over the next couple of years that could draw some more capital that way? Or what types of things make -- or should we expect just more of these kind of small little netback-driven projects across the refining side over the next few years?

Ryan Todd:

Okay. Thanks.

Paul Cheng:

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

Greg Bram:

I agree.

Gary Simmons:

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

Gary Simmons:

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

Gary Simmons:

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

Operator:

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

Gary Simmons:

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

Eric Fisher:

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

Operator:

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

Greg Bram:

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

Jason Gabelman:

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

Jason Gabelman:

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

Jason Gabelman:

Understood. Thanks, Jas.

Matthew Blair:

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

Matthew Blair:

Great, thank you. And then I had another question on capital returns. So, keeping in mind that the Q4 buybacks were quite strong, payout ratio of 73% clearly impressive. We just found intriguing that your cash balance actually showed a build year-over-year in 2023. And I would say you started the year with maybe $2 billion of excess cash, ended the year with maybe $3 billion of excess cash. So could you talk about why that happened? Were there any mechanical limits on buybacks or where you locked out of the market? And then of that $3 billion in excess cash that you have now, do you have any sort of internal targets on -- you look to pay down maybe $1 billion or $2 billion of that in 2024?

Matthew Blair:

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

Lane Riggs:

Yeah. And so we changed that. I don't know, it's a couple of years. We're really coming out of COVID. Going into COVID, we'd taken the strategy trying to push it all the way down to two. And found going into COVID our experience was that was probably too low. So we've decided to bring on go ahead and look at our minimum closer to four. Good thing about being a four now versus two before we actually do earn a return on that cash before it was zero. So -- but that's really due to our experience as we went through COVID.

Operator:

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

Operator:

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

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation's third quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Although attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now, I'll turn the call over to Lane for opening remarks.

Homer Bhullar:

Thanks, Lane. For the third quarter of 2023, net income attributable to Valero stockholders was $2.6 billion or $7.49 per share compared to $2.8 billion or $7.19 per share for the third quarter of 2022. Adjusted net income attributable to Valero stockholders was $2.8 billion or $7.14 per share for the third quarter of 2022. The refining segment reported $3.4 billion of operating income for the third quarter of 2023 compared to $3.8 billion for the third quarter of 2022. Refining throughput volumes in the third quarter of 2023 averaged 3 million barrels per day, implying a throughput capacity utilization of 95%. Refining cash operating expenses were $4.91 per barrel in the third quarter of 2023, higher than guidance of $4.70 per barrel primarily attributed to higher-than-expected energy prices. Renewable Diesel segment operating income was $123 million for the third quarter of 2023 compared to $212 million for the third quarter of 2022. Renewable diesel sales volumes averaged 3 million gallons per day in the third quarter of 2023, which was 761,000 gallons per day higher than the third quarter of 2022. The higher sales volumes in the third quarter of 2023 were due to the impact of additional volumes from the DGD Port Arthur plant, which started up in the fourth quarter of 2022. Operating income was lower than the third quarter of 2022, primarily due to lower renewable diesel margin in the third quarter of 2023. The ethanol segment reported $197 million of operating income for the third quarter of 2023 compared to $1 million for the third quarter of 2022. Ethanol production volumes averaged 4.3 million gallons per day in the third quarter of 2023, which was 831,000 gallons per day higher than the third quarter of 2022. Operating income was higher than the third quarter of 2022, primarily as a result of higher production volumes and lower corn prices in the third quarter of 2023. For the third quarter of 2023, G&A expenses were $250 million and net interest expense was $149 million. Depreciation and amortization expense was $682 million and income tax expense was $813 million for the third quarter of 2023. The effective tax rate was 23%. Net cash provided by operating activities was $3.3 billion in the third quarter of 2023. Included in this amount was a $33 million favorable change in working capital and $82 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 $3.2 billion in the third quarter of 2023. Regarding investing activities, we made $394 million of capital investments in the third quarter of 2023 of which $303 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $91 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD capital investments attributable to Valero were $352 million in the third quarter of 2023. Moving to financing activities. We returned $2.2 billion to our stockholders in the third quarter of 2023 of which $360 million was paid as dividends and $1.8 billion was for the purchase of approximately 13 million shares of common stock resulting in a payout ratio of 68% of adjusted net cash provided by operating activities. This results in a year-to-date payout ratio of 58% as of September 30, 2023. With respect to our balance sheet, we ended the quarter with $9.2 billion of total debt, $2.3 billion of finance lease obligations and $5.8 billion of cash and cash equivalents. Debt to capitalization ratio, net of cash and cash equivalents was 17% as of September 30, 2023 and we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Separately, as reported by Navigator last week, they cancelled their CO2 pipeline project. We still see carbon capture and storage as a strategic opportunity to reduce the carbon intensity of conventional ethanol, which would also qualify it as a feedstock for sustainable aviation fuel. Without carbon capture and storage, conventional ethanol does not have a pathway into staff under today's policies. We continue to evaluate other projects to sequester CO2. Turning to guidance. We still expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modelling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges

Theresa Chen:

I'd first like to ask about your outlook for near-term refining margins and specifically on the gasoline side. We've seen that significant volatility recently, especially early in October. What do you think explains the recent downside? And how does compare with demand across your footprint? Maybe going back to Lane's earlier comments on your wholesale system? And just generally, how do you think gasoline margins trend going forward?

Theresa Chen:

Thank you. And on the crude oil side, in terms of light heavy differentials, given the heightened geopolitical risks in the Middle East and coupled with the incremental Venezuelan production following the recent sanctions relief and taking also into account the potential near-term start-up of just focus [ph]. How do you think about the impact of all these variables on light heavy differentials? And how this evolving from here?

Operator:

The next question is coming from Sam Margolin of Wolfe Research.

Gary Simmons:

Yes. So on the first part of the question in terms of even more seasonality around gasoline, I can't say that we're really seeing that. We did see sales throughout our whole system fall off a little bit after Labor Day but they've actually recovered quite nicely, and we're back into that 1 million barrels a day of sales. Gasoline sales year-over-year are up 2% in the current market from where they were last year at this time. Diesel sales are up a little stronger at 8% so I don't think it really is a seasonability factor that's impacting gasoline at least in the domestic markets.

Operator:

The next question is coming from Doug Leggate of Bank of America.

Lane Riggs:

I'm going to hand this off to Gary and Greg, I think, Gary, you might answer the heavy sour part and then Greg wanted to answer this capture rate on the coker.

Greg Bram:

Yes. And Doug, what I'd say about the cokers, it operated very well for the quarter, certainly consistent with our expectations. And so the project is generating good strong economic value, both by lowering feedstock, some of the things Gary is talking about and also enabling us to increase throughput.

Gary Simmons:

I don't think there's any impact today.

Jason Fraser:

Yes. Thanks, Doug. Yes, it's okay. I'll talk about our approach to buybacks is driven by our thoughts around cash, the dividend debt. So I'll walk you through that and how we're looking about -- thinking about the rest of the year and then we can see -- more you won't be on that. So on cash, as you said, we ended the quarter at $5.8 billion. We've indicated mid target of $4 million [ph]. So we're very comfortable with us being in that current range now. On the debt side, we always practically look at our portfolio through a liability management lens on an ongoing basis, but we certainly don't have any needs to pay down any debt at this time. Net debt to cap as of September 30 was 17%. So it's a bit under our target range. So we're in good shape there. And on the dividend, we maintain a dividend is competitive, growing and sustainable through the cycle. And we feel like we're in a reasonable range now. I wouldn't want to get into more specific on timing or potential dividend increases at this time. And then that brings us to buyback and you know our post to buybacks is to have the annual target of 40% to 50% of adjusted net cash from operations, and we view the buyback as a flywheel supplementing our dividend to hit whatever our target is for the year. In the third quarter, we had a 68% payout year-to-date through the third quarter, we're at 58%. So I would say, under these conditions, even given the softer seasonality in the fourth quarter, you should definitely expect us to pay out over 50% for the year. And as you may recall, the pandemic, that was a fairly regular practice of 5 years before the pandemic, I think we averaged like a 57% payout. So in these periods where we have greatly above-average free cash generation, that will probably continue to be our practice.

Jason Fraser:

No, no, it does. We look at it on an annual basis, and I would think we'll be over 50% for the year. So it definitely does...

Ryan Todd:

Maybe could you talk through a little bit about what you're seeing in renewable diesel markets. 2Q margins were obviously quite soft indicators been weak. Can you talk -- was there any impact from hedging losses in the quarter and maybe could you help us if there were kind of a rough estimate of maybe what that was? And then can you just more broadly talk about what you're seeing in terms of supply demand in the marketplace impact of RIN pricing and RVO limitations, et cetera?

Ryan Todd:

Okay. And then maybe switching on the refining side, as we think about PADD 5, it was really quite strong through third quarter on a relative basis across the country and into the early part of the fourth quarter. Can you talk maybe about what you're seeing overall in terms of kind of supply/demand in PADD 5 across your operations there? There's a lot of moving pieces with some refineries that are -- that have transitioned off the market from conversions right now. So how do you -- as you look forward on the next -- do you expect that market to stay relatively tight for the foreseeable future? And how do you think about it relative to your operations there?

Operator:

The next question is coming from Manav Gupta of UBS.

Lane Riggs:

This is Lane. So the way I would -- I agree with you, and that's -- we still believe we can -- we'll spend somewhere between $0.5 billion to $1 billion a year of strategic capital. But when you look at sort of what's the nature of those, certainly on the refining side, they are going to be shorter cash cycle types of projects instead of a big like a coker type project there'll be a series of small projects. And then when you further drill down and what do we look for? We look for refining projects to lower our cost to produce. We also like projects and improve our reliability and then, of course, we like to hold renewable line in terms of its ability for us to drop the carbon intensity of our fuels. And as you also said, we're very careful about our communication on projects. We'd like to be a little closer to FID or at FID before we really talk about them.

Gary Simmons:

Yes, this is Gary. So if you look, there's about 250,000 barrels a day of exports in Venezuela, most of that volume is going to the Far East. But with the lifting of sanctions, it has the potential to make its way to the U.S. Gulf Coast.

John Royall:

So we've talked about coastal light heavy dips and how they've tightened up pretty significantly. Can you remind us how much flexibility you have in your system to run lights versus heavies versus mediums?

John Royall:

Great. And then maybe you can talk about the beat and utilizations in 3Q. You didn't call out anything in particular, but you're above the high end and I think every region, but one. It seems like the system ran quite well. Are there any moving pieces to call out maybe maintenance getting pushed out or anything of that sort or is it just better-than-expected operations?

Operator:

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

Gary Simmons:

Yes. So diesel demand remains very strong. I guess I mentioned diesel sales in our system are up about 8% year-over-year. Our view of the broader markets is that diesel demand in the U.S. is probably down about 1% year-to-date from where it was last year, and that's mainly due to the warmer winter we had last year. Our guys' estimate, we lost about 125,000 barrels a day of diesel demand due to the warmer weather. So inventories remain below the 5-year average level, demand remains good. So you're heading into winter with low inventories, and we would expect strong diesel cracks through the winter and could get very strong if we have a colder winter.

Lane Riggs:

Yes, we absolutely see. California has become kind of the ore of the RD market. We see more opportunity in Oregon, Washington and Canada as kind of the growth opportunities. And so we absolutely look to maximize our product sales into those markets. California continues to talk about the obligation for 2030. They sort of pushed off a lot of their -- they're still doing a lot of their conferences and workshops on that. We still fully expect that at some point, they are going to announce the changes to be effective sometime next year, and that will increase the LCFS price in California. So -- but in the meantime, we continue to look at -- again, you kind of mentioned that. We still have the advantages being on the Gulf Coast. Do you have access to all of the global feedstocks. You have access to all the global markets so it gives us a lot of capability to go to different markets. And we continue to see waste oils advantaged versus vegetable oils from a CI standpoint. So you look at that low-cost producer on the Gulf Coast, that just continues to be kind of the winning formula for being able to have flexibility to go to different markets in the RD space [ph].

Neil Mehta:

Lane, first question is for you is just -- it's been a couple of months since you stepped to the job as CEO. Just would love your perspective on early observations, recognizing the strategy has been very consistent and steady for a long time, and you've been a big part of it. But early observations as the new leader of the organization and key strategic priorities that we haven't really talked about here on the call thus far.

Neil Mehta:

Now that's -- we definitely see the consistency. The second question is -- it's a very -- it's a smaller part of your business, but it's always -- you can create volatility in earnings is ethanol. Just you're curious on your outlook for that business and -- what -- how far away are we from mid-cycle as you think about it?

Operator:

The next question is coming from Paul Cheng of Scotiabank.

Gary Simmons:

So if I understand correctly, the first was how much really does the gasoline pool well as you go to higher RVP gasoline. Is that what you were asking, Paul?

Greg Bram:

Yes, Paul, this is Greg. So you're right. You definitely increase the amount of primarily butane that you blend into the gasoline. It ranges depending on which region ring and the change in specs, it's in the 5% to 10% range. And then you're right that to the extent that butane has a higher octane than the pool, it does allow you to put more of the lower octane component into the blend [indiscernible] one of those right now that looks pretty attractive.

Lane Riggs:

No, I was just going to answer you -- I think it was your same question around turnarounds. We sort of have a policy for a while that we don't give any real outlook on our turnaround or the industry turnaround behavior. So.

Lane Riggs:

I think -- if I understand, Paul, back to winter blending. Obviously, [indiscernible], butane is relatively cheap. And we always look at economic signals to try to determine how much gasoline are produced and that compares to sort of the reformulated grade, they might require less butane. And then there are specs that you hit, I mean you would think you would get near 10% in butane in full, but a lot of times we hit other specifications and the finished gasoline besides RVP. And so I mean, it's a fair.

Jason Gabelman:

I wanted to first go back to uses of cash or returns of cash, I should say. And I know Valero has a 40% to 50% payout ratio. It seems like you're returning a majority of the excess cash post dividends via buyback, maybe 2/3 of that excess cash. Is that kind of how we should think about return of cash moving forward essentially all of the excess cash or the majority of it beyond what you pay out in the dividend is going to be going towards the buyback for the foreseeable future. And I think some color around that could help the market bring some of that potential future buyback value forward? And I have a follow-up.

Jason Gabelman:

All right, great. And my second one is kind of on the strategic growth outlook. We've seen some of your larger peers use equity to buy up comped recently? And if I think about some of the potential areas you could expand into like chems, like low carbon fuels, those valuations have come down relative to where Valero trades. I don't know Valero doesn't typically use the equity to acquire other companies. But given what's going on with Navigator Pipeline and looking at your potential future growth opportunities, are you taking a closer look at strategic M&A and using equity given your stock and refiners in general have held up pretty well relative to other potential step-out opportunities?

Operator:

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

Lane Riggs:

So Roger, this is Lane. So as you know our history, we were a big consolidator in the industry going back to 2000. That to really our last major acquisition was sort of circa 2013. That's when our base became somewhat like it looks today. So we understand probably as well as any operator out there would it take to buy something or to merge something and get it on our system and all the costs associated with it. And we always get everything that we think within reason. I mean we always analyze everything and -- we haven't bought anything like I said, since 2013 on any refining assets. You never say never. We look at everything, and we'll again, like I alluded to on Jason's question, we'll run it through our processes and figure out where there anything that makes sense for us or not.

Lane Riggs:

Clear on that, Roger. They got to compete with everything else, including buyback, right? So.

Lane Riggs:

Yes. I think as I mentioned before, there's this kind of constant talk about oncoming production, increased rates, Arthurs [ph] projects that has always said at some point the D4 is going to be under pressure especially since the EPA did not raise the D4 obligation in their last set rule. So I think though, is -- and then we combine that with there is this kind of a rush, I think, look like to me kind of a rush to sell RINs in the third quarter with that narrative, combined with that Russian announcement that they were going to ban exports, which kind of quickly evaporated. So there's, I think, a kind of a more of a temporary view that the D4 [ph] was going to drop even more. And like you've observed, it's kind of recovered and fat prices have also since adjusted. We could see that biodiesel and veg oil RD is negative now. That's one of the things we've always said is that the lower CI waste oil play was always going to be more advantageous. So even at these lower credit values, we're still the advantage platform. So as you go into 2024, obviously, obligations already set. It's hard to tell exactly where that's going to go. There's no doubt that R&D will continue to grow. We do see that for us, you're going to see R&D continue to grow, as we talked before, Canada is a big outlet, which takes a lot of this RIN exposure away and then you also obviously have the SAP project come on, where we'll diversify into a different market. And so -- and then and if for some reason, SAP doesn't work, that product also meets Arctic diesel grades that again, go to Nordic countries and Canada. So there's no doubt that there's going to be a continued pressure on the RINs for both the D4 and D6 but our strategy has always been -- there's other markets that you can minimize the impact of that. And then with our platform, we're still the most advantaged from a cost and CI standpoint.

Operator:

Our last question for today is coming from Matthew Blair of Tudor, Pickering, Holt.

Lane Riggs:

No, we usually don't give that kind of detail. I would say it wasn't large, just [indiscernible] at that.

Gary Simmons:

Yes, I'll take the first part of it and then let Rich Walsh handle the second part. Yes, our exports, if you look at the exports in the third quarter, we did 389,000 barrels a day, 281 a distillate, 108 of gasoline. Based on second quarter, the volumes are up based on historic numbers, they trended up as well to our typical export locations. Most of the line went to Latin America, about 70% of the diesel in Latin America and about 30% to Europe. And those are remaining at those levels as we move into the fourth quarter.

Operator:

Thank you. At this time, I'd like to turn the floor back over to Mr. Bhullar for closing comments.

Operator:

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

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation's second quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Lane for opening remarks.

Homer Bhullar:

Thanks, Lane. For the second quarter of 2023, net income attributable to Valero stockholders was $1.9 billion or $5.40 per share compared to $4.7 billion or $11.57 per share for the second quarter of 2022. Second quarter 2022 adjusted net income attributable to Valero stockholders was $4.6 billion or $11.36 per share. . The Refining segment reported $2.4 billion of operating income for the second quarter of 2023 compared to $6.2 billion for the second quarter of 2022. Adjusted operating income was $6.1 billion for the second quarter of 2022. Refining throughput volumes in the second quarter of 2023 averaged 3 million barrels per day, implying a throughput capacity utilization of 94%. Refining cash operating expenses were $4.46 per barrel in the second quarter of 2023, lower than guidance of $4.60, primarily attributed to lower-than-expected natural gas prices. Renewable Diesel segment operating income was $440 million for the second quarter of 2023 compared to $15 2 million for the second quarter of 2022. Renewable Diesel sales volumes averaged 4.4 million gallons per day in the second quarter of 2023, which was 2.2 million gallons per day higher than the second quarter of 2022. The higher sales volumes in the second quarter of 2023 were due to the impact of additional volumes from the start-up of the DGD Port Arthur plant in the fourth quarter of 2022. The Ethanol segment reported $127 million of operating income for the second quarter of 2023 compared to $101 million for the second quarter of 2022. Adjusted operating income for the second quarter of 2022 was $79 million. Ethanol production volumes averaged 4.4 million gallons per day in the second quarter of 2023 which was 582,000 gallons per day higher than the second quarter of 2022. For the second quarter of 2023, G&A expenses were $209 million and net interest expense was $148 million. Depreciation and amortization expense was $669 million and income tax expense was $595 million for the second quarter of 2023. The effective tax rate was 22%. Net cash provided by operating activities was $1.5 billion in the second quarter of 2023. Excluding the unfavorable change in working capital of $1.2 billion in the second quarter, and the other joint venture member share of DGD's net cash provided by operating activities, excluding changes in its working capital, adjusted net cash provided by operating activities was $2.5 billion. Regarding investing activities, we made $458 million of capital investments in the second quarter of 2023, of which $382 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance; and $76 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD, capital investments attributable to Valero were $433 million in the second quarter of 2023. Moving to financing activities. We returned over $1.3 billion to our stockholders in the second quarter of 2023, of which $367 million was paid as dividends and $951 million was for the purchase of approximately 8.4 million shares of common stock resulting in a payout ratio of 53% of adjusted net cash provided by operating activities. Last week, we announced a quarterly cash dividend on common stock of $1.02 per share payable on September 5, 2023, to holders of record at the close of business on August 3, 2023. With respect to our balance sheet, we ended the quarter with $9 billion of total debt, $2.3 billion of finance lease obligations and $5.1 billion of cash and cash equivalents. The debt-to-capitalization ratio net of cash and cash equivalents was 18% as of June 30, 2023. And we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modeling our third quarter operations, we expect Refining throughput volumes to fall within the following ranges

Manav Gupta:

Guys, I just want to quickly start with and congratulate Gary for the promotion and the new rule and all our best wishes are with you. The first question I have for you is that when we look at DGD, you guys have a track record of bringing projects online before time. So is there a possibility a year down the line, you could take a look at it and say, we would like to have similar upgrades possible at DGD 1 and 2 to make more sustainable aviation fuel on a go-forward basis?

Manav Gupta:

Good. The second question here is the DOE data is telling us whatever it is, and there are obviously some concerns around demand out there, but the cracks are telling us a completely different story. The cracks are telling us the demand for products is remarkably strong. So just wondered if you could highlight some of the -- what you're seeing in terms of demand in various regions?

Manav Gupta:

Thank you so much for the detail response. Thank you.

John Royall:

Hi. Good morning. Thanks for taking my question. So my first one was just on the coker. It sounds like you're running full now in the start-up went as planned. But maybe you can just go through any puts and takes around profitability? I know heavy diffs have come in, for example, the diesel cracks are improving recently. Should we think about there being a structurally higher Gulf Coast capture now? And any way to think about quantifying that?

John Royall:

Great. And then maybe along the same lines, it would be great to get your thoughts on heavy and medium sour diffs from here with OPEC+ cutting and the second round of the STR release is now over. What are your thoughts on whether we'll see a widening from here on mediums and heavies or will we likely stay in the current environment where from a sour diffs perspective?

John Royall:

Thank you.

Theresa Chen:

Good morning. On the SAF front, would you mind giving an update on the Navigator BlackRock CCS project? And how is the permitting and right-of-way procurement process going?

Theresa Chen:

Thank you. And in terms of additional SAF opportunities in the DGD facilities, Eric, can you just opine a bit more on how would you think about like the key hurdles it would take to cross to commercialize additional FID?

Theresa Chen:

Thank you.

Doug Leggate:

Thanks. Good morning everybody. Gary, perhaps I could pick on you a little bit given your recent good news. Congrats from me as well. But diesel, a couple of months ago, the world was coming to an end in terms of consensus expectations. And today, we're back at winter-type premiums for distillate cracks. So, I know you touched on it already in some of your comments. But can you maybe speak to what you're seeing that's driving that strength? And I want to address specifically what you're seeing in Asia as it relates to trading. Our understanding is Chinese exports are down and maybe that's creating some globally. So, I'm just wondering if you can offer any perspective as to why the split is as strong as it is today?

Doug Leggate:

So I hope this isn't a second question. This is kind of a clarification question. So are you suggesting that Russian exports are starting to -- they're starting to slow, which I think was the expectation. Is that -- am I reading your comments correctly?

Doug Leggate:

Okay. Thank you. My follow-up is on capture rates. And it seems to us -- I mean, Refining looked in line with consensus for this quarter. The balance was pretty weak capture in the Mid-Con and North Atlantic. So I'm curious if you can walk us through whether that's transitory, if there was anything specific in the quarter? And how you see it trending so far in the third quarter? Whoever wants to take that? Thanks.

Doug Leggate:

And how is that trending in Q3?

Doug Leggate:

All right. Thank you, guys.

Operator:

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

Greg Bram:

Good morning, Paul.

Gary Simmons:

Yeah. So certainly, the big move in the crude market has been the OPEC+ production cuts, 4.5 million barrels a day off the market. And I think you're seeing that as global oil demand picks up, and those barrels are not yet back on the market, you're seeing flat price trend higher, and you've definitely seen it in the quality differentials as well. But in addition to the OPEC+ cuts, there were a number of other issues that you mentioned. We had maintenance in Canada on the wildfires in Canada, the platform fire in Mexico. You kind of went from a seller out of the SBR to a buyer into the SBR. So all of those things had a significant impact on the quality differentials in the second quarter, and we're seeing some of those things start to reverse as we move into the third quarter.

Greg Bram :

Paul, this is Greg. I don't know that we can speak a whole lot to what was going on elsewhere. Our operations were very good for the quarter. Good mechanical availability in line with kind of our typical first quartile type of performance. So the weather has had just a very modest impact on any of our operations.

Gary Simmons :

No. That wouldn't include really what we're talking about on renewables. That would be strictly our U.S. wholesale volumes. I think some of it was due to rationalization that occurred in the industry that allowed us to be more competitive, but we've gone through and in many locations, renegotiated terminal agreements that just allow us to be more competitive in some regions where we haven't been historically and capture additional market share.

Operator:

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

Eric Fisher :

Yes. We definitely had -- there's always some timing of ships in our numbers for the quarter, but we do also have the unit running above its original design capacity. So we are running higher rates at DGD 3 as well as seeing strong sales throughout the world as we move into a lot of production moving into Canada with its new CFR that went live in July, and then there's other states that are coming on beyond California. So overall, yes, we did see increased sales due to the combination of some timing of ships and then obviously, we're running above design rates.

Eric Fisher :

Yes. The margin -- on the margin capture side, we definitely saw prices lower in the second quarter. We saw waste oils become advantaged again. So that improves a lot of our capture rate. If we talk a little bit about RINs and LCFS, those have been pretty much as expected. LCF market has been relatively flat. The EPA came out with its new RIN outlook, and it was largely unchanged. So -- but overall, that's mostly a product. Gary mentioned, we've seen strong ULSD demand. That's the basis of the formula plus, I would say, more attractive fat prices, as you already mentioned.

Lane Riggs:

Yes. This is Lane. So you can really expect us to continue to look to optimize and look at opportunities around our existing assets. We've been doing that. Some of them aren't big or flashy, but in cumulative, they'll have an effect on our overall performance, and we continue to gate those, just like we always have. And then in the other side of the business, our renewable side. We are looking at the potential to always the gain and develop innovative projects that are sort of in the transportation fuel space that leverage our operations excellence and our project execution capabilities.

Operator:

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

Greg Bram:

Yes, this is Greg. So on the West Coast, we had great operations out there. But really, the thing to note there is Benicia has a very, very high gasoline yield in terms of its product mix. So, when gasoline is very strong relative to distillate products out in the West Coast, we see strong capture rates out there driven by Benicia's yield. That's the primary factor you saw in the second quarter.

Lane Riggs:

Let me -- this is Lane. It's really driven by slightly higher outlook for natural gas in the third quarter than the second quarter.

Operator:

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

Gary Simmons:

Roger, we have modeled that, but I don't have the number in front of me, and I don't want to give you a bad number, but we can follow up with you with Homer and get you the number we had on heating oil demand.

Greg Bram:

Roger, we've been mostly in max gasoline mode, but we've been watching that movement between those two products. And we'll make that shift when we start to see that kind of swing cut drive us back the other way. One of the things maybe just to keep in mind is on that swing cut, as you keep that heavier part of the gasoline and the gasoline pool, it pulls in more butane into the blend pool. And when you look at where butane prices are currently that's really attractive to get as much butane in the blend as you can.

Lane Riggs:

Thanks.

Paul Cheng:

Hi. Good morning.

Paul Cheng:

Congratulations to everyone with new role. May be ask -- I apologize because I joined late. So if my question is ready to address, just let me know and we look at the transcript. Two questions. First, with the heavy oil discount and medium sour has also come down like most discount, it doesn’t seems like it's really that attractive to-date. Is it really problem for you guys to run those barrels? And if it's not, is there any way that -- for you to further minimize and what is the minimum that you have to run? The second question is that in the law of Avantec, is there any reason why the margin capture jobs so severely from in the second quarter. I mean not just comparing to the first quarter, but comparing to the last couple of years that you've been running, say, call it 100%, 95% to maybe 120%. And so -- is there any particular reason or there is some one-off unit circumstances that we are seeing? Thank you.

Greg Bram:

Hey, Paul, I'll start with the first one on the different crudes. If I understood your question, we see incentive to run the heavy grades as well as the light track now. The advantage for heavy crudes narrowed quite a bit as we got into the quarter. As Gary mentioned, as those differentials start to move back out that will increase the incentive to move -- to continue to process the heavy grades. The medium sours have probably been the one that have been least attractive and we would need to see those be -- have a wider discount to the light sweet grade before we would start to make a shift there. On your question, your capture rate question.

Greg Bram:

Yes, we can minimize quite a bit. Paul, one thing to keep in mind is there's different parts of the country, different parts of even the Gulf Coast region, where the medium sours, particular grades will still be attractive to run and we'll process those in the places where that medium grade is not as attractive. The easiest way to think about it is, in a lot of cases, we can run a combination of heavy and light to essentially kind of mirror what a medium grade looks like, but do that at a lower cost than buying the medium sour crude itself.

Greg Bram:

Okay. The your capture rate – was around north Atlantic,

Greg Bram:

Yes, Paul, primarily the one thing that was unique about the second quarter was the higher crude cost and again, driven by higher prices for Syncrude out of Canada, both maintenance and wildfire-related. That was probably the thing that caused, kind of, that region to look different this quarter than it would typically for a second quarter period.

Greg Bram:

No, it's much higher than that, Paul.

Paul Cheng:

Okay. Great. Thanks a lot.

Nitin Kumar:

Hi. Good morning all and thanks for taking my question. I just want to start with, can you comment on the recent EPA decision to deny RFS favors for small refiners? And how does that look for your ethanol business I think you mentioned volumes were flat, but can you talk a little bit about pricing for ethanol?

Eric Fisher:

Yeah. And then as far as the commercial impact of that, it's a bit -- we see the same thing, but of a nonevent and we really don't know the compliance posture of those small refiners. So it's not -- we don't see a big impact to any of our businesses on the small refinery section.

Lane Riggs:

This is Lane. When you look at our history on our sustaining capital and some of these things, we were actually ahead of our competitors looking elective gas recovery and some of these other things. So with respect to regulatory capital, we're in good shape, and we're still willing to stick with our $1.5 billion of sustaining. On average, that doesn't mean it can ebb and flow really with turnaround timing.

Operator:

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

Lane Riggs:

Thanks, Neil. So I mean, Joe and I really -- I worked with Joe on the strategy for the last nine years. Obviously, Jill and I go way back before that. So it's not like I've been a part of the current strategy that's been successful. I don't think you should expect us to deviate substantially from where we've been strategically in terms of my areas of focus. I think the first area of focus is just making sure everybody understands exactly that, right? We are -- we have a -- we've been very successful in our execution, maintaining our operations excellence our ability to execute squarely and be great executor of the projects. And I want to make sure that, that continues. And I want to make sure that we stay disciplined, we stay predictable and those are all the things that I think I need to make sure that's going on for the foreseeable future. And a that, I'm going to let Joe keep working in this innovative project space look for our opportunities to spend some of our strategic capital and in some of these opportunities that are around our assets, whether Diamond Green or SaaS or some of the other things that we obviously have done been ahead of everybody else, and we think we can continue to be that company.

Lane Riggs:

Yes. I don't think there's any revisiting of our approach to capital really strong performance. And I'm sorry, with regard to like buybacks and dividend we're going to continue our same approach as well. As far as going above our long-term target of 40% to 50% return to shareholders. Historically, back before the pandemic, we had been at the high end or above our target range pretty regularly. And then last year, we got back to the 45% midpoint of our range, while at the same time getting our debt back down to prepayment levels and building cash. So we got ourselves back in the good posture that we were comfortable with. And we'd also said with that accomplished, we'd be at the midpoint or above going forward. In the second quarter, like you said, we were up above our 50% range. We had a 50% -- 53% payout. Year-to-date, we're at a 52% payout -- so this year, we've clearly trended above 50%. And going forward, as in the past, as I said back before COVID was an unusual circumstance for us we won't hesitate to pay out above the upper end of the range for the year, where we think that's the best use of our excess cash under the circumstances. And on the dividend, we continue to have the same approach to it. We want our dividend to be positioned, we want our yield to be positioned competitive versus our peers who wanted to be growing and sustainable through the cycle. So that continues to be our approach on the dividend. That's how we'll set it and then the buybacks will continue to serve as a flywheel to round out our return to get us to our targets.

Jason Gabelman:

Yeah. Hey, thanks for taking my questions. First, I want to ask on the renewable fuel standard as well and the outlook for RIN prices and the impact of the business, there's a decent amount of concern that there's going to be an oversupply of RINs next year, and that has implications both for Diamond Green Diesel as well as on refining and the ability to capture some of the pass-through of the RIN cost in the crack. So I was wondering, if you have any comments around your RIN outlook as it relates to impacts to both of those segments given some risk to RIN prices moving lower next year? And I have a follow-up. Thanks.

Jason Gabelman:

I mean, I guess if I could just push back a little bit. There is a lot of new renewable diesel capacity coming online next year. So it does seem like there's going to be a lot more RIN supply. I don't know if that enters into your thought process as you look out next year?

Jason Gabelman:

Okay. I appreciate that. And then my follow-up is just going back to the outlook on cracks. And I think a lot of investors have been surprised that the strength we're seeing in cracks and so kind of two parts to this one. Do you think the kind of hotter-than-normal weather globally has supported diesel demand at all? You've already mentioned that you're not going to comment on refining operations of your peers in the warm weather. So wondering if there's been a demand impact, though, from the high weather? And then the second part is, -- can you talk about just given you mentioned inventory product inventories are low. The path forward to rebuilding those, given the global capacity seems to be running all out how does the world restock gasoline and diesel, which are at or below historical levels? Thanks.

Jason Gabelman:

Great. Thanks for the color.

Q – Matthew Blair:

Hi, good morning. Thanks for taking my questions. Do you have any thoughts on the expected impact on RD margins in 2025 when the BTC converts to a PTC. As we look at it, it appears the dollar per gallon subsidy would go down with the PTC, but then, it seems like you might be helped out by just less competition from foreign RD imports. Does that make sense on your end? And is there anything else you would add there?

Q – Matthew Blair:

Great. Thank you. And then on the ethanol side, is an alcohol to jet SAF projects still a long-term possibility? And could you -- if so, could you compare that to what you're doing currently at DGD? Like how do the two production techniques compare in terms of capital cost, operating cost, scale and do airlines distinguish between the two different types of fuel?

Q – Matthew Blair:

Understood. Thanks for your comments.

Homer Bhullar:

Thanks, Donna. I appreciate everyone joining us today, and please feel free to contact the IR team if you have any follow-up questions. Have a great day. Thanks, everyone.

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2023 Earnings Conference Call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our earnings release and filings with the SEC. Now I'll turn the call over to Joe for opening remarks.

Homer Bhullar:

Thanks, Joe. For the first quarter of 2023, net income attributable to Valero stockholders was $3.1 billion or $8.29 per share compared to $905 million or $2.21 per share for the first quarter of 2022. First quarter 2023 adjusted net income attributable to Valero stockholders was $3.1 billion or $8.27 per share compared to $944 million or $2.31 per share for the first quarter of 2022. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying earnings release tables. The Refining segment reported $4.1 billion of operating income for the first quarter of 2023 compared to $1.5 billion for the first quarter of 2022. Refining throughput volumes in the first quarter of 2023 averaged 2.9 million barrels per day, which was 130,000 barrels per day higher than the first quarter of 2022. Throughput capacity utilization was 93% in the first quarter of 2023 compared to 89% in the first quarter of 2022. Refining cash operating expenses were $4.78 per barrel in the first quarter of 2023, lower than guidance of $4.95, primarily attributed to higher throughput and lower natural gas prices. Renewable Diesel segment operating income was $205 million for the first quarter of 2023 compared to $149 million for the first quarter of 2022. Renewable diesel sales volumes averaged 3 million gallons per day in the first quarter of 2023, which was 1.3 million gallons per day higher than the first quarter of 2022. The higher sales volumes in the first quarter of 2023 were due to the impact of additional volumes from the start-up of the DGD Port Arthur plant in the fourth quarter of 2022. The Ethanol segment reported $39 million of operating income for the first quarter of 2023 compared to $1 million for the first quarter of 2022. Ethanol production volumes averaged 4.2 million gallons per day in the first quarter of 2023, which was 138,000 gallons per day higher than the first quarter of 2022. For the first quarter of 2023, G&A expenses were $244 million and net interest expense was $146 million. Depreciation and amortization expense was $660 million, and income tax expense was $880 million for the first quarter of 2023. The effective tax rate was 22%. Net cash provided by operating activities was $3.2 billion in the first quarter of 2023. Excluding the unfavorable change in working capital of $534 million in the first quarter and the other joint venture member share of DGD's net cash provided by operating activities excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $3.6 billion. Regarding investing activities, we made $524 million of capital investments in the first quarter of 2023, of which $341 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance, and $183 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD, capital investments attributable to Valero were $467 million in the first quarter of 2023. Moving to financing activities. We returned over $1.8 billion to our stockholders in the first quarter of 2023, of which $379 million was paid as dividends and $1.5 billion was for the purchase of approximately 11 million shares of common stock, resulting in a payout ratio of 52% of [indiscernible] net cash provided by operating activities. With respect to our balance sheet, as Joe mentioned, we completed additional debt reduction transactions in the first quarter that reduced Valero's debt by $199 million through opportunistic open market repurchases. We ended the quarter with $9 billion of total debt, $2.4 billion of finance lease obligations and $5.5 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was 18% as of March 31, 2023. And we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modeling our second quarter operations, we expect Refining throughput volumes to fall within the following ranges

Manav Gupta:

Congrats on a very good result. I'm not sure if there are many other refiners out there who can show this kind of capture with such heavy turnaround. So congrats on that. I have two quick questions and I'll ask them upfront. We keep seeing DOE data, which is prone to revisions, but sometimes doesn't actually make too much sense. So Joe, in your system across various products, what are you seeing in terms of demand for various products in your system? And the second and related question is, help us understand a little bit what's going on in the diesel market. Are we suddenly oversupplied? Is the demand weak? If you could just talk through those diesel dynamics.

Gary Simmons:

Yes, sure. So, so far, our 7-day average in our wholesale system, our gasoline sales are up 16% year-over-year. Our diesel volumes are up 25% year-over-year. So our wholesale team continues to do a great job. In March, we set a record at 998,000 barrels a day. In April, the volumes are trending right along those levels. So demand seems very, very strong in our system. And even the DTN data for the wholesale racks across the industry is very strong as well. In terms of your question on diesel weakness, we're just not seeing it. I can tell you, in addition to the wholesale volumes, today, there's domestic arbs that are open from PADD 3 into PADD 2 as we're seeing a surge in agricultural demand that's going along with planting season. You also have a domestic arb open to ship from PADD 3 to PADD 1. We see strong waterborne premiums to go to Latin America. The transatlantic arb is open to Europe. And so for us, distillate fundamentals look pretty good.

Theresa Chen:

Can you comment on your outlook for Gulf Coast capture from here? Clearly, the start-up of the Port Arthur coker should be a tailwind, but we've also seen differentials come in. Net-net, how do you view the profitability of your Gulf Coast system, both near term and longer term?

Theresa Chen:

And on a related note, how do you see the BGO situation evolving in terms of your Gulf Coast consumption as well as the global supply following the EU embargo on Russian products as well as the Saudis exporting less after [indiscernible] on its conversion unit?

Gary Simmons:

Yes. In terms of supply, I think we were concerned that the ramp-up in sanctions against Russia would limit VGO exports and cause VGO tightness. So far, it looks like the Russian barrels are continuing to flow. And so we're not nearly as concerned about VGO supply as we were earlier in the year.

Kalei Akamine:

This is Kalei on for Doug. I've got a follow-up to Theresa's question, and it really goes to the availability of heavy sours that are in the market. There is a perception that, that length is getting shorter with OPEC cuts and then increased demand from new projects such as your coker and perhaps MPC's resid hydrocracker are squeezing the market for those kind of supplies. Can you talk about what you guys are seeing and if the phased start-ups of the new refineries, where not all the units are online, could help alleviate that situation.

Kalei Akamine:

Got it. And a quick follow-up to that. Can you talk about what you're seeing for new refining capacity that's supposed to come online, like Dangote and Dos Bocas in Mexico?

Operator:

Thank you. Our next question is coming from the line of John Royall with JPMorgan.

Jason Fraser:

Yes. No, that's right. This is Jason. And you're right, our balance sheet is in good shape right now. We've got up over $5.5 billion of cash, we feel pretty strong there. We got our net debt to cap ratio down into a good spot around 18%, which is well at the lower end of our range. So we feel like we're in a pretty good spot with regard to any potential recessionary conditions. And as far as our target for where we want to be in our range, we'll continue to target the 40% to 50% when we have strong results. Of course, we'll be looking at the upper end. of that. We ended at 45% last year, paid out 52% this quarter. Actually with the extra cash we had, we did kind of an all-of-the-above strategy, we were able to build our cash by $600 million. Payout at 52% and also paid back a little more debt. So it will just depend on how the year plays out, where we fall in the range, right, in the payout range.

Richard Walsh:

This is Rich. I can start out with just sort of the regulatory climate. California has always been a tough regulatory climate for operations. And so I'm assuming you're talking about the California 2 rulemaking that's out there. And what we would just say is that the bill does have some burden, some reporting requirements in it. And then obviously, it kicks basically a profit tax over to this California Energy Commission to implement it. And so we'll stay active and engaged in that rulemaking process and watch what develops out of the agency there. It's unclear what price cap, if any, they'll ultimately put in place. I would point out that the rulemaking on that, the standard that the agency is supposed to use is they're supposed to determine that the benefits to consumers are outweighed by the potential cost to consumers. And it goes without saying that attempts by governments to artificially limit commodity prices has never been really good for the economy and it ultimately ends up hurting consumers. So we'll just have to see how that all plays out.

Operator:

The next question is coming from the line of Paul Sankey with Sankey Research.

Gary Simmons:

Yes. So our wholesale on the gasoline side, we're up 16% year-over-year. On distillate, we're up 25% year-over-year. March, we set a sales volume record 998,000 barrels a day. And then April, the volumes are trending about like they did in March. So certainly, when you look at the broader DTN wholesale volume data, it's not as significant growth is what we're seeing, and so it indicates we're doing a good job of capturing market share.

Gary Simmons:

Yes. Okay. I'm not counting that as a question, Joe.

Paul Sankey:

I'm in D.C. actually. On the IRA, what's your latest thinking on how that could impact your business in terms of the regulatory environment? We've had -- we've dealt with the California one, I think, on the call already, but if you've got any latest thoughts on how things in Washington are shifting. And the other one, I guess, is a big deal here. Obviously, it's carbon capture and how you're thinking about that.

Paul Sankey:

Yes. Got it. I think that SAF is definitely a very interesting one. Okay. And then generally speaking, in the market, we've seen margins come off an awful lot, which is a bit odd seasonally. Is there anything that you can observe about -- especially given what you're saying about your wholesale margins, your wholesale deliveries. The big sell-off that we've seen here is somehow doesn't seem to be entirely supported by fundamentals. We had a great gasoline demand number, for example, this week in the . Any thoughts on how Q2 is going to shape out? And I'll leave it there.

Operator:

The next question is coming from the line of Roger Read with Wells Fargo.

Gary Simmons:

Yes. So I think there are several factors that come into play there, Roger. Historically, we see an incentive to store summer-grade gasoline or components to New York Harbor. This winter, the market structure really made it where it wasn't economic to do that. And so we did build inventory for that. And then, again, typically in the first quarter, you see a lot of volume going across the Atlantic from Europe into New York Harbor early in the year, and the strikes that occurred in France kind of minimized those volumes as well. So we've come into driving season with 10 million barrels below where we were last year on gasoline inventory. So especially summer grade gasoline is very tight, and it is going to stress the Colonial system as we move into driving season.

Unidentified Company Representative:

Roger, this is Eric. I think we still see a big demand for SAP in the future. The EU just talked about mandating it beginning in 2025 and at increasing percentages as you get to 2030 and 2050. So the IRA isn't the only driver for SAF. I think, between what we see in different jurisdictions starting to obligate jet and make it a mandatory requirement as well as just the internal commitments that a lot of the airlines and cargo carriers have made from a corporate standpoint, we still see that SAF is going to be a strategic growth area for renewables.

Ryan Todd:

Maybe I'll stick for one follow-up on the low carbon fuel side. Can you talk a little bit about a couple of the carbon possibilities that you mentioned earlier in the call, you mentioned renewable [indiscernible] alcohol jet. What would either of those projects look like in your current operations? And are there further changes in product prices or regulatory support that would be required to make either of those businesses make sense?

Ryan Todd:

Great. And then maybe just a quick follow-up on the Port Author coker. Is there -- congratulations on getting that started up. Is there any sort of ramp associated with operations there? How should we expect kind of contributions to that in the second quarter? And any kind of updates or thoughts on what the -- what you think the annualized EBITDA contribution is in the current environment?

Operator:

Our next question is coming from the line of Jason Gabelman with TD Cowen.

Gary Simmons:

Yes. So I think the way we would view it is much like you said, we would view it as it's kind of telling us where the floor on margins. It's not just Asia, but in Europe margins are negative. And so a lot of that is the distillate weakness. We still see diesel inventory very, very low. And we view that some of that capacity should actually be running. And so it's kind of telling you we're the floor on where margins are.

Unidentified Company Representative:

Yes. We've looked at the DGD cash flow, and we would still say we see a distribution in the back half of this year becoming an opportunity for the partners.

Unidentified Company Representative:

No, we're not going to give a number like that out, but it does look positive through the end of the year.

Matthew Blair:

Joe, could you help us understand the Q1 refining capture, a strong figure, a little bit more. I think Lane mentioned butane blending was a tailwind. What else drove it up? And I guess, specifically, were product exports more of a supporting factor than normal? And then also, was there any impact from turning in the 2021 RINs, like any sort of mark-to-market as you submitted the 2021 RINs in March of 23?

Joseph Gorder:

I don't think the RIN had anything to do with it.

Matthew Blair:

Great. And then on the Q2 Refining guidance, it looks like it implies about 90% to 93% utilization. You already did 93% in Q1. So I guess I'd be surprised if it ticks down. Is that just -- should we think about it as just a conservative number? Or are there -- are there major turnarounds that we should be aware of that's pulling down your Q2 expected run rate?

Joseph Gorder:

Yes. And Matthew, I mean, you know our history and our tendency. I mean we're not going to oversell anything. So we'll just -- we'll see how the markets look. And lane's right, we'll operate as appropriate.

Homer Bhullar:

Thanks, Jesse. We appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any questions. Have a great week. Thank you, everyone.

Homer Bhullar:

Good morning everyone and welcome to Valero Energy Corporation's fourth quarter 2022 earnings conference call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero’s senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I'll turn the call over to Joe for opening remarks.

Homer Bhullar:

Thanks, Joe. For the fourth quarter of 2022, net income attributable to Valero stockholders was $3.1 billion or $8.15 per share, compared to $1 billion or $2.46 per share for the fourth quarter of 2021. Fourth quarter 2022 adjusted net income attributable to Valero stockholders was $3.2 billion or $8.45 per share compared to $988 million or $2.41 per share for the fourth quarter of 2021. For 2022, net income attributable to Valero stockholders was $11.5 billion or $29.04 per share compared to $930 million or $2.27 per share in 2021. 2022 adjusted net income attributable to Valero stockholders was $11.6 billion or $29.16 per share compared to $1.2 billion or $2.81 per share in 2021. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables. The Refining segment reported $4.3 billion of operating income for the fourth quarter of 2022 compared to $1.3 billion for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $4.4 billion compared to $1.1 billion for the fourth quarter of 2021. Refining throughput volumes in the fourth quarter of 2022 averaged 3 million barrels per day. Throughput capacity utilization was 97% in the fourth quarter of 2022. Refining cash operating expenses of $5 per barrel in the fourth quarter of 2022 were $0.14 per barrel higher than the fourth quarter of 2021, primarily attributed to higher natural gas prices. Renewable Diesel segment operating income was $261 million for the fourth quarter of 2022, compared to $150 million for the fourth quarter of 2021. Renewable Diesel sales volumes averaged 2.4 million gallons per day in the fourth quarter of 2022, which was 851,000 gallons per day higher than the fourth quarter of 2021. The higher sales volumes were due to the impact of additional volumes from the DGD St. Charles plant expansion and the fourth quarter 2022 start-up of the DGD Port Arthur plant. The Ethanol segment reported $7 million of operating income for the fourth quarter of 2022, compared to $474 million for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $69 million compared to $475 million for the fourth quarter of 2021. Ethanol production volumes averaged 4.1 million gallons per day in the fourth quarter of 2022. The higher operating income in the fourth quarter of 2021 was primarily attributed to multi-year high ethanol prices due to strong demand and low inventories. For the fourth quarter of 2022, G&A expenses were $282 million and net interest expense was $137 million. G&A expenses were $934 million in 2022. Depreciation and amortization expense was $633 million and income tax expense was $1 billion for the fourth quarter of 2022. The annual effective tax rate was 22% for 2022. Net cash provided by operating activities was $4.1 billion in the fourth quarter of 2022 and $12.6 billion for the full year. Excluding the unfavorable change in working capital of $9 million in the fourth quarter and $1.6 billion in 2022 and the other joint venture member share of DGD's net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $4 billion for the fourth quarter and $13.8 billion for the full year. Regarding investing activities, we made $640 million of capital investments in the fourth quarter of 2022, of which $349 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $291 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD and those related to other variable interest entities, capital investments attributable to Valero were $538 million in the fourth quarter of 2022 and $2.3 billion for the year, which is higher than our annual guidance primarily due to project spend timing on the Port Arthur Coker project and the accelerated completion of the DGD Port Arthur plant. Moving to financing activities. We returned $2.2 billion to our stockholders in the fourth quarter of 2022 and $6.1 billion in the year, resulting in a 2022 payout ratio of 45% of adjusted net cash provided by operating activities through dividends and stock buybacks. With respect to our balance sheet, we completed additional debt reduction transactions in the fourth quarter that reduced Valero's debt by $442 million through opportunistic open market repurchases. As Joe noted earlier, this reduction, combined with a series of debt reduction and refinancing transactions since the second half of 2021, have collectively reduced Valero's debt by over $4 billion. We ended the year with $9.2 billion of total debt, $2.4 billion of finance lease obligations and $4.9 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents was approximately 21%, down from the pandemic high of 40% at the end of March 2021, which was largely the result of the debt incurred during the height of the COVID-19 pandemic. And we ended the year well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and $500 million to growth. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges

Theresa Chen:

Good morning, everyone. Thank you for taking my questions.

Theresa Chen:

My first question is related to – good morning. Related to your macro outlook over the near-term. And with respect to Russia, how do you see the EU embargo or price cap on Russian products imports playing out, specifically to the diesel as well as the geo situation?

Theresa Chen:

Got it. And clearly, there's been a focus on an elevated amount of maintenance in the first half of this year, plus some unplanned downtime. How big of an impact do you think this will be on near-term refining economics? How real do you think this is? And what are the implications on your own refining earnings taking into account that you have your own maintenance program to work through as well?

Lane Riggs:

And Theresa, this is Lane. So as we've been pretty consistent, we don't do a lot of commentary around our turnaround activity. But nonetheless, I mean, the first quarter and third quarters are heavy turnaround periods when we have turnarounds. And so that's sort of seasonally, that's how we execute our maintenance.

Operator:

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

Joe Gorder:

Thanks, Doug.

Joe Gorder:

Yes. No, Doug, we'll let Lane take a crack at this one.

Doug Leggate:

Just to be clear, and I know you don't want to be specific on timing, but would you anticipate this up by the end of the second quarter, or how are you thinking about start-up?

Doug Leggate:

Joe, I hate to do this, but I got to ask the cash return question. Your balance sheet, you've managed it or Jason, maybe, back to below COVID levels. Your dividend still hasn't moved and your share count is now down, I guess, about 7%. So, all things considered, it seems you've got a lot of capacity for dividend to restart dividend growth. How can you walk us through what you're thinking on cash returns? Thanks.

Jason Fraser:

Yes, I'll give a little context quarter, we did beat a goal, which will kind of change in how we look at things. So, back prior to the pandemic, we were frequently at the high end or even above our target return payout range of 40% to 50%. Now, during the pandemic, we were very committed to our dividend and paying the dividend loan put us way above our 40% to 50% target range. And as you know, during COVID, we had to take on another $4 billion of debt in 2020. So, one of our main objectives as the financial situations improve post-COVID was the payback this incremental debt, which we've been aggressively working on. And we've messaged that while we're working on this competing goal of deleveraging, we would stay at the lower end of our 40% to 50% payout range, which is what we've been doing. Now, in the fourth quarter, we were able to repurchase $442 million of debt, which is the final step in us meeting our goal of deleveraging by $4 billion. So, with that insight, during the quarter, we increased our stock purchases to $1.8 billion and we're able to end the year at a 45% payout ratio. So, we're able to work our way back to the midpoint of our target range for the full year. And now that we've paid off our pandemic debt and build our cash balance up to a good level, you should reasonably expect us to be looking at mid-level or higher payout targets given the construction margin environment as we move forward. Now, on the dividend side, please go ahead -- yes, you'd asked about dividend too, which is other pieces of the puzzle. So, we continue to aim for a dividend as sustainable and competitive versus our peers. We would also like to show growth. And as you know, the dividends -- we hadn't had any growth since the first quarter of 2020 because, first of all, we had the pandemic, which we had to work our way through. And then we're rebuilding cash and working our debt down. So, now, as I've said, we've kind of met those goals so we would like to return to a pattern of growth as we move forward.

Joe Gorder:

Net zero debt, Doug.

Operator:

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

Gary Simmons:

Yes. So, this is Gary. I think our outlook on crude quality differentials is we expect the market to stay fairly consistent. The key drivers really on the quality differentials have been more sour crude on the market, refineries running at high utilization rates, which produce more high sulfur fuel oil. And then with the IMO 2020 regulation, it's decreased the demand for high sulfur fuel oil. And so all those factors come into play, affecting the supply/demand balances around high sulfur fuel and then high sulfur fuel really drives the quality discount. So we don't see much changing at least in the near-term in terms of where those quality differentials are.

Lane Riggs:

Hey, Roger, this is Lane. I'll take a shot at it. I think what you'll see, and we were concerned about it going into this past year was the VGO availability, but we sort of through with some of the way some of the refineries in the Middle East started up. And I think some people stockpiled VGO, I mean, the answer to that is it will remain tight. And ultimately, what it affects is gasoline production. If you believe distillate cracks are going to hang in there where they are, you'll have clear margins by VGO into a hydrocracker, but it will challenge FCC's economics through the summer, it's in fact, as it gets tight.

Lane Riggs:

Thanks, Roger.

John Royall:

Hey, guys. Good morning. Thanks for taking my question. So I was hoping for your view on China reopening and how that could trickle through the market, particularly when you think about the new refining capacity coming on and they appear to still be releasing big batches of export quota. So anything on China reality would be helpful? Thanks.

John Royall:

Great. Thank you. That's helpful. And then on the Renewable Diesel side, can you talk about how the feedstock market is absorbing DGD 3 and assuming this is the case, why it's been kind of easier than having pushed up advantaged feedstock the way it did with DGD 2?

John Royall:

Thank you.

Sam Margolin:

Good morning. Thank you.

Sam Margolin:

So in the prepared remarks, you mentioned European energy cost driving optimization opportunities in the US via a lot of different factors. But energy costs in Europe have crashed and diesel cracks are still rising and those optimization opportunities are still there. Can you talk a little bit about maybe what's going on in Europe from your perspective that's kind of sustaining these advantages even though the gas cost side is maybe out of the equation?

Sam Margolin:

Okay. That's really helpful. And then I guess just as a follow-on, it's a little bit related, but it's back to Port Arthur. I mean the coker is starting up at this high run rate, and you've got a new renewable diesel facility there that's very cost advantage if for no other reason than just its integration with the refinery. So this is facility that's probably the most valuable fuels complex in the world at this point, I would say. And I don't even know what the question is, to be honest with you, but I'm just trying to get contribution to the system.

Sam Margolin:

Yes. I mean if it has -- if it's dragging up the entire Gulf Coast system with it because of optimization opportunities that it comes with, I mean, just sort of I guess, a plant level contribution would be helpful.

Homer Bhullar:

Contribution at the plant level?

Joe Gorder:

And then obviously, the renewable diesel plant, there is going to be very helpful. So you're right, Sam, it's a very valuable complex to us.

Joe Gorder:

You too.

Paul Cheng:

Hey, guys. Good morning.

Paul Cheng:

Can I go back into Port Arthur, mainly with the coker coming on stream, we understand that, I mean, one of the decisions behind is that you will allow you doing the turnaround, you can still won the facility. But during the long-term around period, how that impact Port Arthur in terms of the cruise lay of throughput and product yield?

Paul Cheng:

No, outside of it. I mean, we understand the turnaround Now, you have two coker.

Paul Cheng:

But I'm more interested if it is not doing the turnaround, how the new coker addition will impact in terms of your [indiscernible], your product, yield and your overall throughput?

Paul Cheng:

Right. So, we assume that is a 55,000 barrel per day, so you will see incremental one of heavy and mediums to the tune of 150,000 barrels per day?

Paul Cheng:

Now, the coker, the capacity is 55,000 barrels per day. Should we assume we're heavier up by about 150,000 barrels per day of the heavy and medium sour crude?

Paul Cheng:

No, no, I'm saying not the overall throughput increased by 150,000, I'm saying that, will you increase the run of heavy and medium sour crude by 150,000 barrels per day with this coker?

Lane Riggs:

We would have to get back to you. It's going to be a lot. I mean, I have to go back and see how much we incremented on in terms of the volume. So, -- and we'll have to get back with you. We can get back with Homer disclose that I don't know. I don't know what--

Lane Riggs:

So Paul, which margin -- Valero's overall--

Lane Riggs:

Well, I didn't really -- it's not that much stronger versus the prior quarter. I mean, just the way we look at it is…

Lane Riggs:

No, but I'm saying versus prior like I said.

Lane Riggs:

Yeah. Capture rate was up just a little bit.

Operator:

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

Gary Simmons:

Yes, I think so. So you can see that a couple of places, you can really see at the low to high spread on fuel oil, you can certainly see the gap that's occurred and then just general weakness in high sulfur fuel. I think it tells you that the industry really is tight on capacity to upgrade high sulfur fuel into low-sulfur products. And we've really seen that starting early last year, and it's continuing, and we don't see anything that changes that.

Jason Fraser:

Well, so one thing that we saw with the RFS obligation is that they kept the ethanol target at 15 billion gallons, which means you're still going to be in a situation at some point in the year where you have to use the D4 RIN to cover the D6 obligation because the ethanol blending won't reach 15 billion gallons. So that mechanism is still in there. To your point, the future obligations were higher, but not as high as people expected. And when you saw that announcement come out, you did see a big drop in soybean oil prices as well as a lot of pressure on – or question on whether or not all these soybean crush facilities were going to get built based on that lower obligation going forward. So it's a little bit of a mixed bag that, there's still going to be short on the D6 RIN, but there is definitely a lower growth curve on the D4 RIN in this current proposal. So we'll have to see how that plays out. There's still a lot of talk about a lot of the policy trying to move away from soybean oil as a feedstock, both in Europe and in the US, at least in terms of conversations. And so as everyone's trying to figure out is that part of what's at play with this lower RFS proposal. So – but overall, as you said, we're a waste oil units that isn't affected by that. And as you said, we will be competitive regardless of the obligation compared to our peers. So we'll have to see how the -- we'll just have to see how this plays out. I don't know, Rich, you had other comments about the future outlook on the RFS proposal. I know we're…

Ryan Todd:

Good. Thank you.

Connor Lynagh:

Yeah. Thanks. I, kind of, want to continue that line of questioning there. I appreciate this is a little bit ridiculous since you just brought DGD 3 online. But what is the policy vision make you think about DGD 4 or some of the opportunities that you'll have when you have your carbon capture system online for your ethanol plants? Just where is your head on where future renewables growth for you guys might be?

Connor Lynagh:

What's your thinking around exploring potential alcohol to jet or other avenues to approach the SAF market.

Connor Lynagh:

All right. Thanks very much.

Neil Mehta:

Yes. Good morning, team and congrats on a great quarter. The first question was around jet cracks. We're seeing that premium relative to diesel really blow out in some markets. Would love your perspective on -- do you think there's a structural premium in jet? And how do you see those premiums playing out over time?

Neil Mehta:

That’s helpful. That to follow-up is around just the demand levels. I mean, we've historically anchored to EIA on some of the US demand levels and the numbers are noisy. I mean in the last four-week trailing number was down 11%, which is hard to reconcile with the fact that disti is 20% below the five-year from an inventory perspective in gasoline below the five-year as well. So just would love to hear what you're seeing through your own wholesale system in terms of demand? And any thoughts on real-time color there?

Neil Mehta:

That makes more sense. Thanks, guys.

Jason Gabelman:

Good morning. I got a couple of questions. First, I wanted to ask about the US Gulf Coast intermediate imports, the resids, and I understand some of that's going to be backed out with the Port Arthur Coker project, but you'll probably be taking some in-sell. And as these resid differentials have widened throughout the year, I imagine it's been a pretty large benefit to your capture rates in 2022. So I was hoping you could help frame that? And if you expect resids the discount to stay wide in 2023 and continue to contribute to stronger captures despite your commentary that you expect some of the Russian VGO to be taken off the market? And I have a follow-up. Thanks.

Gary Simmons:

Yes. So, the only thing I would add is for the full year 2022, resid probably didn't have a significantly positive impact on our capture rates just because after the Russian sanctions and those barrels came off the market for really the second and third quarter, it was rebalancing the trade flows. But in the fourth quarter, we certainly saw a significant impact.

Homer Bhullar:

Maybe I'll start on just on the DGD side, it just started up. We haven't even got to the conversation with cash distributions yet. But the expectation is this year, it should be with capital spending coming to a close with the project that there should be more cash spinning off from the joint venture. I don't know, Jason, if you comment--

Jason Gabelman:

Got it. Thanks.

Matthew Blair:

Hey, thanks for taking my question. Good morning everyone. Do you have any early thoughts on the Q1 2023 refining capture rate? It seems like we might want to be just a little conservative here. I think you're refining guidance implies like 86% to 89% utilization. So, probably a heavier turnaround period. And then some other factors like butane blending and octane spreads still good, but looks like they're coming down from Q4 levels. So, I guess, directionally, does that make sense that we want to be more conservative on capture in Q1 and anything else we should consider there?

Matthew Blair:

Got it. And then for DGD, how should we think about the feedstock mix going forward? Your old guidance was one-third fat, one-third corn oil, one-third uco [ph], but you started up DGD 3 and your partners acquired production. So, it seems like we might want to inch up maybe a little bit on the fat compared to that one-third guidance, maybe inch down on the uco, is that fair? And do you have anything more specific on that?

Matthew Blair:

Great. Thank you.

Homer Bhullar:

Thanks, Donna. I appreciate everyone joining us today. Obviously, if you have any additional questions, please feel free to reach out to the IR team. Thanks, everyone, and have a great week.

Homer Bhullar:

Good morning, everyone, and welcome to Valero Energy Corporation’s third quarter 2022 earnings conference call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer and several other members of Valero’s senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company’s or management’s expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we’ve described in our filings with the SEC. Now, I’ll turn the call over to Joe for opening remarks.