Valero Energy Corp (VLO) — Q2 2024 Earnings Call Transcript

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, along with 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 states 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.

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. 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%. 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 operations, 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.

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, and depreciation and amortization expense was $696 million, while income tax expense was $277 million with an effective tax rate of 23%. Net cash provided by operating activities was $2.5 billion in the second quarter of 2024, which included 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, while 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, with the balance to growth, approximately half of the growth capital directed toward our low-carbon fuels businesses and half toward 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. Regarding 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, including $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, with operating expenses averaging $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.

One of my questions was 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 and demand balance today?

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 of less than 1%. You look at vehicle miles traveled; 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 with diesel sales; four-week average diesel sales in our system are up 10%. Again, we don't necessarily believe that's representative of the broader markets. If you look at year-to-date, diesel sales in the DOE data would suggest a decline in diesel demand of 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, and there was a little less demand from the upstream sector. However, a lot of that has been offset by the increase in jet demand. So about half of that decline was offset with an increase in jet demand. So maybe distillate demand is down slightly. In the U.S., we would say gasoline demand is flat year-over-year, and distillate demand is down slightly. The bigger impact has been on the overall North Atlantic Basin. Certainly, in the North Atlantic Basin, we saw regions with slowing economic activity that negatively affected, 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. 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. Some of that early in the year was masked by some drone strikes on Russian refining capacity. But the combination of higher refinery runs in the Middle East, and a little sluggish economic activity in parts of the Atlantic Basin allowed restocking of inventories in the region. With that, we've obviously seen refinery margins weaken some. We haven't had any major weather event that took 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 aligned with 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 towards the bottom end of the five-year average range. As inventories tend to trend towards the five-year average, you would expect to see a margin environment closer to a mid-cycle type margin environment. That's kind of what we're seeing. It does feel as though 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, and cracking margins in the Far East were negative. If that's correct, and we found the bottom, it has historically been a mid-cycle type refining margin environment. That's actually pretty bullish for refining going forward. As we move into the third quarter, we'll start to see a little lower utilization, mainly turnarounds affecting refinery utilization. Most of the consultant data actually shows year-over-year demand growth weighted more 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, and the market in Europe looks quite strong, which has closed the arb to send gasoline from Europe to the United States and opened 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 for margins in the long term.

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

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

Sure. So, John, we haven't really had to lean into the balance sheet for shareholder returns. 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 in 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 of 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 have 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 to go towards share buybacks.

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. Obviously, Dangote is part of that, but we've had Whiting come back online and utilization, it seems, is 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?

No, I think we see it the same way. I think you'll see some improvement in economic activity, which will enhance diesel demand. For us, you've had the impact of Dangote and the refining capacity 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 think that will tighten the supply-demand balances longer term.

My follow-up is related to that. 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. 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?

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. Historically, the way it works there is you have marginal economics, and then the balances would be such that you'd have a period of higher margins and then it would go back. So it's really almost a call option on West Coast spreads. It is a harder place to operate; it's a more expensive place to operate. When you look across the U.S., I would expect that's probably one of the places that you would ultimately see some refinery closures as this shakes out. And then I'll let Gary.

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, get pretty tight. But if you look from April to the end of June, gasoline imports into the West Coast were up 70,000 barrels a day. I think that, combined with a little softer demand, is why you're seeing that margin environment on the West Coast today. As for TMX, it started up at the beginning of May. They didn't load the first cargo out until the end of May, and 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.

Maybe we 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. 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 the challenges in getting permits for expansions?

This is Rich Walsh. It's not often we get a legal question like this on our earnings call, so it's exciting. I'll try to keep it straightforward. With the removal of Chevron deference, courts are now required to provide their own interpretations rather than deferring to agencies on their own authority. This change makes it harder for the judiciary to allow the administrative state to operate unchecked. The Supreme Court is working to ensure that there is meaningful judicial review. Judges are now expected to interpret statutes themselves instead of simply deferring to the agencies. This could lead to reduced agency overreach in how they interpret laws and less fluctuation in agency policies with changes in administration. Coupled with the major questions doctrine, the Court seems to be aiming to return policymaking powers to Congress rather than leaving them to be decided at the administrative level. We've already seen this shift, as the Supreme Court has sent back nine cases for lower courts to reconsider without giving deference to agencies. While we don't discuss specific ongoing litigations, there have been some extreme interpretations, particularly with the current administration's stance that it can mandate vehicle electrification without Congressional approval. It's difficult to see how courts would grant deference on that issue.

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

There is a California waiver case currently awaiting review by the Supreme Court regarding a specific petition. The DC circuit previously dismissed that case due to a standing issue, avoiding the main question. Several other cases are on the horizon, including a CAFE case that has already been presented to the DC circuit. I believe these changes will take place sooner than most people expect from the judiciary.

There has been a significant impact on supply in the second quarter, and the system has been operating effectively with high utilization rates. I'm interested to know if you notice any reductions in consumer demand in different regions that could affect supply. Your third-quarter guidance suggests lower throughput compared to the second quarter. Is this due to maintenance or is there some commercial activity influencing this? I would like to understand how you view the supply dynamics in the third quarter and if this could positively affect margins.

Ryan, this is Greg. I'll talk about our system. You do see that our throughput guidance considers planned maintenance activity we have in the quarter. Particularly if you take a look at 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.

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?

This is Lane. I think if you sort of listen to Gary's opening comments and consider our position, we do believe going forward, you're going to have a higher margin environment. We're seeing refinery cuts, which indicates to us a return to a mid-cycle margin environment. That says that the market is tightening and that there are refineries which historically would perform in a mid-cycle environment that are being forced to cut back now. That reinforces our view that margins will be higher for capital in the near future.

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

Manav, this is Gary. In the short term, we've seen heavy sour differentials move a little wider. That was mainly due to a Mid-Continent refiner that's had a complete power outage, which decreased the demand for Canadian heavy. As we move through the third quarter, you'll see a turnaround activity in the Mid-Continent, which should also decrease demand for Canadian heavy, supporting the differentials. Longer term, 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 our view has been late this year, early next year, you start to see more OPEC barrels in the market, which will create wider heavy sour differentials. The other point to note is that even with where the differentials were in the second quarter, we saw a significant economic uplift by running heavy sour crudes, even with the differentials at current levels.

For my follow-up, as you're approaching completion on the SAF unit, are there any preliminary estimates on how much of an uplift transitioning from early to SAF could provide to you guys?

Manav, this is Eric. We are not going to give out specific estimates like that. I would say you can look at the various programs, like state programs and federal tax credits around whether it's BTC or PTC, and then the mandates in the EU and the U.K., which can provide some indicators of what that uplift might be. Argus has quotes that you can look at. What I would say is that there is a premium for SAF over renewable diesel, and it's all going to result in a margin that will be stronger than renewable diesel. Our outlook is that we'll meet the economics of our projects, and all of that looks positive.

I wanted to go back to one of Gary's comments earlier on demand across your footprint, particularly 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 capture market share, which seems to be on a continued basis at this point?

Well, I guess I'd just say our wholesale team has done a great job for us on growing our market share. 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.

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?

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 that the RIN market still looks oversupplied to us. As we approach the back end of '24, it seems that the RIN market will be long and the California LCFS market will remain long. Therefore, we expect compression in renewable diesel margins in the back half of '24. The policy matters that are coming up, LCFS might expand with California. They're still saying that's going to be a change in 2025. The RIN update for 2026 got pushed to March of '25. Based on expectations around RFS volumes for Ag, we expect there will probably be some sort of increase. So I think longer term, over the next one to two years, we see a lot of tailwinds for DGD in terms of credit prices. Specifically for our platform, we are diversifying into SAF, which includes a premium over renewable diesel. So that looks pretty strong. Another important aspect now is whether we will have a BTC or PTC transition on January 1. As we've mentioned previously, the relationship between RIN and BTC means that when we discussed BTC going away, we expected the RIN to increase to maintain the biodiesel producer at breakeven. Transitioning from BTC to PTC, where the PTC is less than $1, might force the RIN to increase to cover the difference for biodiesel blenders to remain at breakeven. These are market discussions and the credits look long, but the relationship between BTC, PTC, and RIN has traditionally been a market balancing factor. Timing of these changes, especially with elections, remains up in the air, but structurally, much looks positive for DGD.

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 TMX is now fully retracted in the marketplace? Or do you think over the several months that we do have solutions for the crude deficits in that market? Secondly, maybe this is either for Gary or for Lane. As the market normalizes, how does it impact how your refining operations run in terms of the sustainable maximum run rate crude yield or product yield? Any comments would be great.

Yes. I'll start with TMX, Paul. Yes, I think it took a little while for the West Coast market to respond to TMX. However, if you look at where ANS was trading prior to the TMX start-up, and where it is relative to Brent now for September, 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 in the third quarter.

I'll take a shot at the second one. Paul, this is Lane. I don't really see that as the world settles in. Our operations will remain consistent. We always take signals from the market. We focus on being reliable and executing our turnarounds based on operational excellence rather than solely on market conditions. Our goal is to execute in a manner where we are the best operator that we can be, which we believe we are. Therefore, I don't see any profound changes based on refining outlook.

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

Yes. 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. With where PEMEX was pricing the barrels, we had better alternatives. It’s not a major shift. Moving forward, we do think you'll see some growth in our Mexico volumes. Our terminal that we'll utilize in Altamira will start up before the end of the year, which will allow us to be more competitive in the Northern Mexico market and continue to grow our volumes there.

Shifting over to renewable diesel. So I know you talked about this a little earlier, and feedstock costs have been higher over the past couple of months, but could you just talk 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?

Yes. We've noticed that there is growing competition for waste oils. We're still the largest importer of foreign waste oils. If I compare this year to last year, there was a pretty good arb of foreign feedstocks over domestic feedstocks being more advantaged. It looks like that's largely incorporated now, and domestic feedstocks seem to be the most attractive from a cost standpoint. Those are all the most advantaged feedstocks for renewable diesel from a CI standpoint, but we see overall, particularly waste oil feedstocks, starting to increase. So I would say feedstock prices appear to have bottomed out in the second quarter and are starting to trend up a little bit in the third quarter, largely attributed to some of the start-ups we see in California.

Staying on refining, I would love your perspective on the coking market, especially in light of Port Arthur coming online, which is a really good asset. What is your perspective on fuel oil and the opportunities around coking and how those margins can start to normalize over time? What's the sequence of events that could get us there?

Neil, this is Greg. 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. I don't believe that we're seeing a significant step change going forward. As Gary mentioned, as you get more medium sour and heavy crude into the market later this year, that should enhance that value. But for now, it's still a strong opportunity for us and continues to outperform our other modes of operation, which we're looking to maximize.

For my follow-up, it's around Asia and specifically around China. As we look at oil demand data, one of the things that has disappointed our model has been Chinese domestic demand. Do you see this as part of the contribution to some of the softness in PADD 5 and the Asian refining margin lift in the absence of strong Chinese demand?

Neil, this is Gary. We don't have a lot of visibility into the markets in the Far East. But I can tell you that what we read indicates, especially diesel demand in China has declined. We see a decrease of as much as 10%, largely due to reduced construction activity there. For the most part though, it seems they've adjusted refinery runs to maintain balance on exports. While exports are up slightly, we haven't seen a significant shift in their exports.

I wanted to go back to the wholesale channel growth. It has been pretty consistent over the past few years. I'm wondering if you could provide some sort of earnings estimate in terms of an uplift from selling through that channel relative to may be some pre-COVID period or other baseline you have available. Do you expect that growth to continue?

Yes. The only comment is, we don't provide a lot of detail around our wholesale margins. The growth is because that channel provides the most positive netback for our Gulf Coast system and our U.S. system, which is why we continue to push it to grow. So that should be reflected in capture rates going forward, but we don't provide detailed margins.

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

Yes, I can tell you roughly. If you look three years ago, we were consistently in the 850,000 barrel range, and now we're over 1 million barrels a day. So somewhere around 150,000 barrels a day of growth in wholesale is what I'd tell you over the last few years.

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

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?

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

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

Yes, there were a few things going on in the second quarter that I think impacted this period. One, we always talk about the seasonal RVP change in gasoline and how that negatively affects margin capture as you pull the butane out of the gasoline, which you can do in the winter. That was certainly a piece. We also saw crude market backwardation fairly strong in the second quarter, which affects crude costs, specifically the acquisition cost for crude. Yes, that was probably $0.80 to $0.90 a barrel relative to the prior quarter and even looking back at some of the other periods in time. We discussed the co-products: naphtha, propylene in particular. Another bit unique to the second quarter was that we pride ourselves on our ability to secure opportunity feedstocks to run in our system, especially in our Gulf Coast system with flexibility. In the second quarter, there simply weren't many opportunities to secure those feedstocks, not because we weren't looking, it was just the way the market played out. That was a bit unique from what we've seen before. I expect we'll see more opportunities looking forward into future periods.

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

Sure. On the ethanol side, this increased margin is really a result of low natural gas prices as well as inexpensive corn. If you look at all the carryout numbers for this year, with Brazil having a record crop, and the U.S. expected to have a record crop, the carryout is going to be substantial. That means we're still carrying a fairly large inventory of corn from last year. The upcoming harvest is projected to yield another high inventory. I see corn remaining cheap barring a weather event or something dramatic in Brazil. Therefore, I am quite positive on the ethanol outlook for the rest of this year and into next year. Afterward, it will typically be a harvest-to-harvest outlook based on subsequent crop forecasts. As for Summit, that's not our project; it's a question for Summit. They just got their approval in Iowa. We view carbon sequestration as a supportive strategy for ethanol, but we're merely a shipper on that project. If and when they get the project operational, we will connect to it and provide volume into that system, but we do not have much insight into the project itself.

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.