Valero Energy Corporation (NYSE:VLO) Q2 2024 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q2 2024 Earnings Call Transcript July 25, 2024

Valero Energy Corporation beats earnings expectations. Reported EPS is $2.71, expectations were $2.6.

Operator: Greetings. Welcome to Valero Energy Corp.’s Second Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note, this conference is being recorded. I will now turn the conference over to Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. You may begin.

Homer Bhullar : Good morning, everyone, and welcome to Valero Energy Corporation’s 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.

Lane Riggs: Thank you, Homer, and good morning, everyone. We are happy to report strong financial results for the second quarter. Our refineries operated well and achieved 94% throughput capacity utilization. We saw continued strength in our U.S. wholesale system with sales exceeding 1 million barrels per day in the second quarter. We also saw a good contribution from our renewable diesel and ethanol segments. On the strategic front, our growth projects are progressing on schedule. The Diamond Green Diesel sustainable aviation fuel project in Port Arthur is still expected to be operational in the fourth quarter. At which point, DGD is expected to become one of the largest manufacturers of SAF in the world. And we continue to pursue short-cycle, high-return optimization projects around our existing refining assets.

On the financial side, we remain committed to shareholder returns with a year-to-date payout of 80%. And last week, we announced a quarterly cash dividend on our common stock of $1.07 per share. Looking ahead, limited announced capacity additions beyond 2025 should support long-term refining fundamentals. In closing, our team’s simple strategy of pursuing excellence in operation return-driven discipline on growth projects and a demonstrated commitment to shareholder returns has underpinned our success and positions us well for the future. So with that, Homer, I’ll hand the call back to you.

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: Gulf Coast at 1.77 million to 1.82 million barrels per day; Mid-Continent at 405,000 to 425,000 barrels per day; West Coast at 235,000 to 255,000 barrels per day and North Atlantic at 390,000 to 410,000 barrels per day.

We expect refining cash operating expenses in the third quarter to be approximately $4.70 per barrel. With respect to the Renewable Diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2024. Operating expenses in 2024 should be $0.45 per gallon, which includes $0.18 per gallon for non-cash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.6 million gallons per day in the third quarter. Operating expenses should average $0.40 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $140 million and total depreciation and amortization expense should be approximately $690 million.

For 2024, we expect G&A expenses to be approximately $975 million. That concludes our opening remarks. Before we open the call to questions, please limit each turn in the Q&A to two questions to ensure other callers have time to ask their questions.

Q&A Session

Operator: [Operator Instructions] Our first question is from John Royall with JPMorgan.

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?

Gary Simmons : John, this is Gary. I think in the U.S., for the most part, the economy has been fairly resilient and the market fundamentals look pretty similar to what we’ve been looking at the past couple of years. If you look at our wholesale data, four-week average, our gasoline sales are up about 0.5%. There tends to be a lot of noise in the weekly DOE data. But year-to-date, DOE data would suggest a slight decline in gasoline demand less than 1%. You look at vehicles mile travel, they’re up 1.4%, which would again indicate a slight increase in demand for gasoline. I guess the way we’re looking at it is, we’d say, year-over-year, gasoline demand in the U.S. is flat. On the diesel side, we’re actually showing a pretty good step change in our system on diesel sales, four-week average diesel sales in our system are up 10%.

Again, don’t necessarily believe that’s representative of the broader markets. If you look at year-to-date, diesel sales and the DOE data, it would suggest a decline in diesel demand about 100,000 barrels a day. Directionally, I think that makes sense to us with a little weaker freight numbers early in the year. You didn’t really have any help from weather, a little less demand from the upstream sector. However, a lot of that has been offset with the increase in jet demand. So about half of that offset with an increase in jet demand. So maybe distillate demand down slightly. In the U.S., we would say gasoline demand flat year-over-year, distillate demand down slightly. I think the bigger impact has really been for the overall North Atlantic Basin.

Certainly, in the North Atlantic Basin, we saw regions with slowing economic activity that negatively impacted, especially demand for diesel. And then it looks like some of the new capacity that came on in the Middle East really never made it to nameplate capacity until early this year. So we saw a bit of a step change in refining runs in the Middle East with a lot of that product making its way into Europe. So some of that early in the year was masked with some of the drone strikes on Russian refining capacity. But the combination of higher refinery runs in the Middle East, a little sluggish economic activity in parts of the Atlantic basin allowed restocking of inventories in the region. So with that, we’ve obviously seen refinery margins weaken some.

We haven’t had any type of major weather event take down refining capacity like we’ve seen the past few years. Of course, we’re right in the middle of hurricane season so you still have that potential. So with refinery runs up in the North Atlantic basin lined with a little softer diesel demand, you’ve seen that restocking. We’ve gone from well below the five-year average total light product inventory to trending more to the bottom end of the five-year average range. As inventories tend to trend towards the five-year average, you would expect to see margin environment closer to a mid-cycle type margin environment. That’s kind of what we’re seeing. It does feel as the market has found a bit of a bottom consultant data indicates at least earlier this week, hydroskimming margins in Europe and the Far East were negative, cracking margins in the Far East negative.

And if that’s correct, and we found the bottom, it is what historically been a mid-cycle type refining margin environment, that’s — it’s actually pretty bullish refining going forward. As we move into the third quarter, we’ll see — start to see a little lower utilization, mainly turnarounds affecting refinery utilization. Most of the consultant data actually shows year-over-year demand growth was more weighted to the back end of the year. So hopefully, we see a little bit better demand. Some of the freight indices are starting to turn. Market in Europe looks actually pretty strong, which has closed the arb to send gasoline from Europe to the United States, open the arb to send U.S. Gulf Coast diesel to Europe. So I think you’ll see some tightening of supply-demand balances in the near-term.

And then longer term, we see very little new refining capacity additions with continued demand growth, which should be bullish margins in the long-term.

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?

Jason Fraser : John, this is Jason. I might just ask Homer to answer that one for you.

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.

Operator: Our next question is from Doug Leggate with Wolfe Research.

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?

Gary Simmons : No, I think we see it the same way. I think you’ll see some improvement in economic activity, which will improve diesel demand. And then for us, you’ve had the impact of Dangote and [Despoc] starting to be absorbed in the market. Offsetting that, there are 600,000 barrels a day of announced refinery closures. We’re not sure when the timing of those will actually occur. But as you start to see more refinery rationalization occur, I don’t again tighten up the supply-demand balances longer term.

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?

Lane Riggs : Doug, this is Lane. I’ll start and then I’ll let Gary follow-up on the TMX question. When you think about our portfolio, the West Coast clearly is the highest cost region we operate in. It’s just by virtue of everything that goes on in the West Coast, it’s the most expensive to operate with. And historically, the way it works there is you have marginal economics and then the balances would be such that you’d have an allergen, you would sort of experienced a period of higher margins, and then it would go back. So it’s really almost a call option on West Coast spreads. And it is a harder place to operate is a more expensive place to operate. And so when you look across the U.S., I mean, I would expect that’s probably one of the places that you would ultimately see some refinery closures in this shakes out. And then I’ll let Gary.

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.

Operator: Our next question is from Roger Read with Wells Fargo.

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?

Richard Walsh : This is Rich Walsh. And so, hey, you never get a great legal question like this on our earnings call. So this is exciting. And so I’m going to try not to get too wonky here, but I just — with Chevron deference, right, the — under that program, the courts were required to give agencies complete deference as to their interpretations to their own authority. And so it made it really difficult for the judiciary to kind of rein in the administrative state. And so what you see the Supreme Court doing is they really basically restored a meaningful judicial review over this. So that now judges are required to use their best reading of the statute. And while the agencies have historically viewed that they’re entitled to this deference and the agencies generally believe they’ve got the right reading of the statute.

I think everybody is going to kind of come to the realization that the range of interpretation that’s going to be acceptable is not is not going to be as wide. And you’re clearly going to have judges who are empowered now to kind of look at the statute and not just defer to the agency on it. So as a practical matter of how that works is I think you’re going to see less agency overreach in terms of how they interpret it and you’re certainly going to see less political swings in the agencies in terms of how they often shift back and forth depending on the administration. And then I think if you kind of pair that together with major questions doctrine and you’re really looking at kind of trying to — I think what the court is trying to do is put policy back in the hands of the legislator back in the hands of Congress and not let it be really policy driven at the administrative level.

And so — and just as a practical matter, we’ve seen that already happen. The Supreme Court sent back nine cases already asking the lower courts to review their decisions in light of not giving deference to the agency. So when you talk about our existing litigations, we really don’t talk about the litigation specifically, but I would say you’ve seen some pretty extreme interpretations here, in particular, the administration taking the position that they, without congressional mandate can go in and mandate electrification of vehicles. That’s hard to see how that — how the courts give them deference on that question. And it’s certainly hard to see how that’s not already covered under the major questions doctor in the West Virginia case. So I feel like I’m getting a little wonky here.

So let me just kind of wrap that up with that thought.

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?

Richard Walsh : Well, there’s already a California waiver case queued up in front of the Supreme Court on a [certain] petition. Now it was — the DC circuit dismissed that one based on a standing type issue, but they really were trying to avoid, I think, addressing the underlying question. So it will be — there’s a number of cases coming up. There’s a CAFE case that’s already been argued in front of the DC circuit that specifically queued up. So I think these changes will happen quicker than people traditionally expect from the judiciary.

Operator: Our next question is from Ryan Todd with Piper Sandler.

Ryan Todd : Maybe one back on refining supply/demand. Clearly, part of the issue in the second quarter here has been supply driven. The system has been running really, really well with high utilization rates. Are you seeing — just curious if you look at the consumer, are you seeing run cuts across any parts of the globe that you can see have an impact on the supply side. And as you look at your third quarter guidance, it implies lower throughput versus 2Q, is that maintenance? Is there some commercial activity there? Just curious as you see kind of how you see dynamics on the supply side here in the third quarter as a possible tailwind for margins?

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.

Ryan Todd : And then maybe on a broader question. I mean, you’ve argued for generally tight global refining markets and probably higher for longer type of mid-cycle margins. Has anything from the 2024 margin environment that we’ve seen this year change this view? Or do you still view that kind of as consistent with the outlook going forward?

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.

Operator: Our next question is from Manav Gupta with UBS.

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.

Gary Simmons : Manav, this is Gary. So I think in the short-term, we’ve seen heavy sour differentials move a little wider. That was mainly a Mid-Continent refiner that’s had a complete power outage that’s decreased the demand for Canadian heavy. As we move through the third quarter, you’ll see a turnaround activity in the Mid-Continent, especially also decreased demand for Canadian heavy, which is supportive of the differentials. And then longer term, I think the two things you pointed towards, for meaningful, sustainable wider heavy sour differentials, you really need more OPEC production back on the market. We’re unsure exactly when that occurs. But yes, our view has been late this year, early next year, you start to see more OPEC barrels on the market, which will create wider heavy sour differentials.

The other thing I’d point to is even with where the differentials were in the second quarter, we saw a significant economic uplift by running heavy sour crudes in the second quarter even with where the differential were.

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?

Eric Fisher : Manav, this is Eric. We were not going to give out like specifics like that. I would say you can look at the various programs, the state programs, the federal tax credits around whether it’s BTC or PTC and then the mandate in the EU and the U.K. all kind of give you an indicator of what that uplift will be Argus has got a quote that you can look at. What we would say is that there is a premium of SAF over RD, and it’s all going to be give us a margin that will be stronger than RD. And our outlook is that we’ll meet the economics of our projects. So all of that looks pretty positive.

Operator: Our next question is from Theresa Chen with Barclays.

Theresa Chen : I wanted to go back to one of Gary’s comments earlier on demand across your footprint, the 10% year-over-year uptick on the diesel side, which is not representative of the broader market. Can you give some color on how you’ve been able to take market share what seems to be on a continued basis at this point?

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.

Theresa Chen : And following up on the renewable fuel economics, Eric, can you provide an update on your outlook for the different subsidy prices over the near to medium-term, especially with the election around the corner?

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.

Operator: Our next question is from Paul Cheng with Scotiabank.

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.

Gary Simmons : Yes. I’ll start with TMX, Paul. Yes, I think that it took a little while for the West Coast market to respond to TMX. If you look though at where ANS was trading prior to the TMX start-up, and kind of where September is trading relative to Brent, ANS has come off in the $1.50 to $2 range, which is in line with what we thought the impact TMX would have on West Coast crude costs. I just don’t think you’ll see that show up until more third quarter.

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.

Operator: Our next question is from Joe Laetsch with Morgan Stanley.

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.

Gary Simmons : Yes. So this is Gary. I would tell you our volumes to Mexico were down a little bit. We’ve been fairly consistently sending about 100,000 barrels a day in the second quarter that was more like 87,000 barrels a day. For us, it’s just another knob we have in optimizing our Gulf Coast system. And with where PEMEX was pricing the barrels, we had better alternatives. It’s not a shift. Moving forward, we do think you’ll see some growth in our Mexico volumes. Our terminal that we’ll utilize an Altamira will start up before the end of the year. It will allow us to be more competitive in the Northern Mexico market and allow us to continue to grow our volumes there.

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?

Eric Fisher : Yes. We have noticed that there is growing competition for waste oils, we’re still the largest importer of foreign waste oils. So if we look at that they were used — if I compare it to last year, there was a pretty good arb of foreign feedstocks over domestic feedstocks being more advantaged. What we see that is that’s largely incorporated and now domestic feedstocks look to be the most attractive from a cost standpoint. From a CI standpoint, those are still all the most advantaged feedstocks for RD, but we do see overall particularly waste oil feedstocks starting to increase. So I would say it looks like feedstock prices have bottomed out here in the second quarter. They’re starting to trend up a little bit in the third quarter, largely attributed to some of the start-ups that we see in California.

Operator: Our next question is from Neil Mehta with Goldman Sachs.

Neil Mehta : Staying on refining, I just love your guys perspective on the coking market, especially in light of Port Arthur coming online, which was a really good asset. And just your perspective on fuel oil and the opportunity around how of coking and how that those margins can start to normalize over time? What’s the sequence of events that we’ll get back to tap?

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.

Neil Mehta : And then the follow-up is around Asia and specifically around China, as we look at oil demand data, one of the things that disappointed our model has been Chinese domestic demand. Do you see it — as you look at the data, and that’s a part of the contribution to some of the softness in PADD 5 and in the Asian refining margin lift in the absence of strong Chinese demand?

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.

Operator: Our next question is from Jason Gabelman with TD Cowen.

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?

Gary Simmons : Yes. The only comment, we don’t really give a lot of detail around our wholesale margins. Obviously, the growth is because that’s our most — the positive netback for our Gulf Coast system and our U.S. system, and that’s why we continue to push it to grow. So that should be reflected in capture rates going forward, but we don’t really give a lot of detail on what those margins are.

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?

Gary Simmons : Yes, I can, roughly. I mean, you look three years ago, we were fairly consistently in the 850,000 barrel range and now over 1 million barrels a day. So somewhere in the neighborhood of 150,000 barrels a day of growth in wholesale is what I’d tell you over the last few years.

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.

Jason Gabelman : And then just specifically on results in refining. I think co-products were a pretty decent headwind to capture. I’m wondering how much that shaved off capture rates in 2Q and if you’re seeing any reversal of those headwinds going into 3Q, especially as crude has started to fall?

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.

Operator: Our next question is from Matthew Blair with Tudor, Pickering & Holt.

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?

Greg Bram: So this is Greg. Yes, there were a few things going on in the second quarter that I think had some impact specific to this period. One, we always talk about the seasonal RVP change in gasoline and how that can have a negative impact on margin capture as you pull the butane out of the gasoline that you were able to do in the winter time. So certainly, that was a piece. We also saw crude market backwardation fairly strong in second quarter, which impacts crude cost, the acquisition cost for crude. Yes, it was probably $0.80 to $0.90 a barrel relative to prior quarter and even looking back at some of the other periods in time. We talked about the co-products, naphtha propylene in particular. And I think the other thing maybe worth noting that is a bit unique to the second quarter, we always pride ourselves on being able to go secure some of those opportunity feedstocks that we can run in our system, particularly in our Gulf Coast system with all the flexibility we have there.

And I would just tell you in the second quarter, just the way the market played out, there just wasn’t a lot of that opportunity to be had, not that we weren’t looking for it. It’s just the way kind of the market shaped up. And so that’s a bit unique from what we’ve seen in the past. And I would expect we’d see those kind of opportunities when we look forward going in future periods.

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?

Eric Fisher : Sure. On the ethanol side, this increased margin is really a result of cheap natural gas prices as well as cheap corn. If you look at all of the carryout numbers for this year, with Brazil having a record crop, the U.S. having a record crop forecasted, the carryout is going to be pretty large. That means we’re still carrying a fairly large inventory of corn from last year. The harvest that’s coming up is going to be another large inventory. So we — so I see corn fairly cheap barring weather event between now and harvest or something dramatic in Brazil. So I think the — I’m positive on the ethanol outlook for the next — for this — the rest of this year and into next year. After that, it’s always harvest to harvest of what the next outlook will look like after that.

As far as Summit, that’s not our project. That’s really a question for Summit. They just got their approval in Iowa. We still view carbon sequestration as a supportive strategy for ethanol, but that’s — we’re just a shipper on that project. So if and when that gets put in the ground where we’ll happily hook up to it and provide volume into that system, but we don’t really have a whole lot of insight into the project itself.

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.

Homer Bhullar: Great. Thank you. I appreciate everyone joining us today. As always, feel free to contact the IR team if you have any additional questions. Thank you, and have a great week.

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