Valero Energy Corporation (NYSE:VLO) Q2 2023 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q2 2023 Earnings Call Transcript July 27, 2023

Valero Energy Corporation beats earnings expectations. Reported EPS is $11.36, expectations were $5.08.

Operator: Greetings, and welcome to the Valero Energy Corp. Second Quarter 2023 Earnings Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you. Please go ahead.

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.

Lane Riggs: Thank you, Homer, and good morning, everyone. Before we discuss quarterly results, I want to thank Joe Gorder for everything he’s done to build upon Valero’s 43-year history. Joe steered a repositioning of our strategy and the commitment to shareholder returns through capital discipline, innovation and strong execution. I’m grateful for his leadership and proud of what Valero has accomplished, and I’m honored to build on that foundation as we continue to advance our position as a leading manufacturer of liquid transportation fuels. Moving on to quarterly results. We are pleased to report solid financial results in the second quarter, underpinned by our strong execution across all of our business segments. Our refineries ran well with throughput capacity utilization of 94% as refinery margins were supported by continued tight product supply and demand balances.

Product demand was strong with our US wholesale system setting a sales record of over one million barrels per day in May and June. We also had a positive contribution from the Port Arthur Coker project, which was started up in early April and is operating well and at full capacity. The new coker has increased the refinery’s throughput capacity and enhance its ability to process incremental volumes of heavy crude and residual feedstocks. Our Renewable Diesel segment set records for operating income and sales volumes in the second quarter, driven by incremental production volumes from Diamond Green Diesel, Port Arthur. The Diamond Green Diesel sustainable aviation fuel project at Port Arthur is progressing on schedule. Plan is expected to have the ability to upgrade 50% of the current 470 million gallon annual renewable diesel production capacity through Sustainable Aviation Fuel or SAF, is expected to be complete in 2025 and have estimated a cost of $315 million, with half of that attributable to Valero.

With the completion of this project, DGD is expected to become one of the largest manufacturers of SAF in the world. These projects expand our long-term competitive advantage, and I want to commend our projects and operations team for their dedication and execution. We also continue to evaluate other opportunities while maintaining capital discipline and honoring our commitment that all projects meet a minimum return threshold. On the financial side, we returned 53% of the adjusted net cash provided by operating activities to shareholders through dividends and share repurchases in the second quarter. And we ended the second quarter with a net debt to capitalization ratio of 18%. Looking ahead, we expect low global light product inventories and tight product supply-and-demand balances to continue to support refining fundamentals.

Copyright: Elnur / 123RF Stock Photo

Global demand for transportation fuels has recovered substantially with gasoline and diesel demand now comparable to pre-pandemic levels and jet fuel demand continues to increase steadily. In closing, we remain committed to the core strategy that has been in place under Joe’s leadership for nearly a decade. Our focus on operational excellence, capital discipline and honoring our commitment to shareholder returns have served us well and will continue to anchor our strategy going forward. So Homer, with that, I’ll hand the call back to you.

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: Gulf Coast at 1.77 million to 1.82 million barrels per day; Mid Continent at 450,000 to 470,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 435,000 to 455,000 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 2023. Operating expenses in 2023 should be $0.49 per gallon, which includes $0.19 per gallon for noncash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4.4 million gallons per day in the third quarter. Operating expenses should average $0.39 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $690 million.

For 2023, we expect G&A expenses, excluding corporate depreciation, to be approximately $925 million. That concludes our opening remarks. Before we open the call

See also 10 Best Small Cap Electric Vehicle Stocks to Buy and 11 Best Logistics Stocks to Buy.

Q&A Session

Operator: [Operator Instructions] Today’s first question is coming from Manav Gupta of UBS.

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?

Eric Fisher: Yes. Manav, this is Eric. Obviously, that is a possibility because those are cookie-cutter units, and we could do the exact same project at St. Charles that we are currently underway at Port Arthur. It’s too early to talk about any numbers or commitment, but yes, that’s definitely something we’re looking at and something that we could do.

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?

Gary Simmons: Yes, Manav, this is Gary. We do believe that the DOE is understating gasoline demand. But even their data is showing on a 4-week average basis gasoline demand up about 3%. But if you look at our numbers, of course, Lane mentioned we had record volumes in both May and June of over 1 million barrels a day. We’re seeing gasoline sales in our system up 14% year-over-year, up 22% from pre-pandemic levels. Gasoline inventory year-over-year is down 7.5 million barrels. So it’s trending at the low end of the 5-year average range. Typically, this time of year, you have an open arb to ship barrels from Europe into the United States. But with inventory low in Europe, that arb is closed, which is hindering imports, and we see strong export demand from the U.S. Gulf Coast into South America.

So the fundamentals around gasoline look very good. Diesel inventory is up 6 million barrels, but continues to trend below the 5-year average range. Diesel inventory is flat, where historically, this time of year, we start to see diesel building. Again, while the DOE reflects weaker diesel demand year-over-year, it looks like the weekly data is continually being revised up. So although we certainly that we had a weaker heating oil season, diesel demand looks fairly similar to last year. So we moved forward a lot of encouraging signs around diesel where we saw weaker tonnage index in the second quarter, the June data reflects that the tonnage index is picking back up. We’ll start to see more agricultural demand as we get into harvest season and more heating oil demand as we get into colder weather.

Continue to see very good export demand from the US Gulf Coast into South America. Some of that has fallen off as we’ve replaced some supply with Russian barrels, but largely been replaced with more export demand from the US Gulf Coast into Europe. Jet demand also picking up, and had a positive impact on overall distillate supply-demand balances, so the distillate demand looks up 10% year-over-year. It looks pretty strong. All the airlines are reporting very strong demand. Jet trading at a $0.10 per gallon premium in the US Gulf Coast on a rent-adjusted basis today. So, yes, the fundamentals look very, very good.

Manav Gupta: Thank you so much for the detail response. Thank you.

Operator: Thank you. The next question is coming from John Royall of JPMorgan. Please go ahead.

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?

Greg Bram: Hey John, this is Greg Bram. So as Lane mentioned, the Coker started up in April. And I think it’s probably worth noting the project and operating teams did a great job bringing that unit online safely without incident. And that’s after we accelerated the schedule last year to be in a position to capture value from that project here in 2023. We’ve ramped it up to full capacity over the course of the quarter, and it’s running well and median expectations. And I think with that, you can take kind of the guidance we’ve given in the past and think about where the market is today and adjust accordingly. I don’t think we have really a new or different view, because the project is really doing what we expected it to do.

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?

Gary Simmons: Yes, this is Gary. I think we have seen the discounts widen back out some as we’ve moved throughout the third quarter. I think there’s some reason for optimism as we head into fall turnaround season, had two and three, you’ll see some decreased demand for heavy sour crude, which will help the differential some. I think we’ll see some more production growth out of Western Canada as they come out of maintenance season, which would put more barrels back on the market, should continue to see a ramp-up in Chevron production from Venezuela heading into the US Gulf Coast. And then finally, there’s some seasonal factors which should help the discounts as well. High sulfur fuel oil for power burn will begin to wind down seasonally, which will put more high sulfur fuel on the market, help the discounts there.

And then as we transition into winter weather, you would expect to see higher natural gas prices, which changes the economics for some refineries around the world that have been processing medium and heavy sour crude, which have helped the discounts as well.

John Royall: Thank you.

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

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?

Richard Walsh: Hi Theresa, it’s Rich. I’ll start out by saying that the Navigator project is progressing. They’ve got parallel proceedings in front of each of the state’s respective utility boards and/or counties and the regulatory proceedings in Iowa are taking longer than they anticipated. And so Navigator is not expecting regulatory approval until the back half of 2024, which will naturally push their timeline back. And they’ve not announced — and they haven’t given any update on a new start-up schedule. So–

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?

Eric Fisher: Yes, I think what I would say about SAF is the airlines are still in very much an educational phase of this. What they’re still trying to wrestle with is I think there is a good understanding of it’s going to come from RD. They’re starting to understand the credit markets and how they work. But as you know, all of these SAF demands, a lot of them are voluntary from the carriers and as well as because it’s voluntary, they’ve got options on, do they want to accept allocation, do they want to accept — which model do they want to operate under, where in the world do they want to run these barrels? And I think the learning that everyone is working through right now is conventional jet is a fungible product. And so the SAF will naturally move into fungible markets, just like jet fuel does.

But as airlines want the specific molecule at their particular location, particular airport, even at the airports, it then becomes a fungible product. So, all of that becomes a conversation of, okay, how do you then take that sort of real-life logistics and apply it into these policies and goals and how do you want to set up a commercial deal with that? So, there’s still a lot of details being worked through on how this will physically move into the market. And then as a result of that, how it will price. So, I think airlines are still — we’re still working through a lot of those details. I don’t see any drop in interest or demand. We see demand still growing strongly through 2030. So I think there’s still a lot of upside in this outlook. I think it’s — but we have to work through these commercial details and logistical details.

Theresa Chen: Thank you.

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

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?

Gary Simmons: Yes, I think you definitely saw as China ramped up and they didn’t have the domestic demand keep up with that initially, you saw a lot of Chinese exports. Some of those barrels were making their way into Europe. And then you had some trade flows that needed to rebalance with the Russian sanction. So, initially, we saw a decreased demand from Latin America and so diesel was starting to back up in the US. But as trade flows have rebalanced, the Russian barrels that are making their way into Latin America that gap has largely been filled by increased demand from Europe. So, if you look for — in our system in the second quarter of last year, our export is pretty comparable to the second quarter of this year. However, last year, 95% of our volume went to Latin America, 5% to Europe.

Second quarter of this year, we had 60% of our exports go to Latin America with 40% to Europe. So you’re starting to just see a big pull of diesel from the U.S. Gulf Coast into Europe. We thought in the second quarter and thus far in the third quarter, that’s continuing. And that’s the real difference.

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?

Gary Simmons: We have seen Russian exports slow, I don’t know, if that’s just maintenance activity occurring in Russia, what’s driving it. But we have seen some of the South American demand that we feel like we lost the Russian barrels that those countries are back inquiring for supply from us again.

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.

Greg Bram: Yeah, Doug, this is Greg. So as you mentioned, overall capture rates were pretty consistent with what we’d expect from a 1Q to 2Q move. I should mention from the earlier question. In the Gulf Coast, the Coker was a positive impact, the new Coker on capture rates in the Gulf. As you mentioned in the Mid-Con, lower there primarily due to turnaround activity and you can see that in our lower throughput rates in second quarter versus the first quarter. And then in the North Atlantic, we tend to always see a seasonal shift in the value of Canadian distillates up in that market strong in the winter and then coming off in the spring and summer time. So that was one of the effects we saw there. Then the one that was a bit more unique to this particular period was just higher cost for sweet crude coming out of Canada, primarily impacted by some maintenance and also the wildfires they had up there.

Doug Leggate: And how is that trending in Q3?

Greg Bram: Yeah, we’re starting to see it moderate a bit, but it will take some time. That usually is not just a very short, short-term effect, but we expect that it will start to improve.

Doug Leggate: All right. Thank you, guys.

Greg Bram: Thanks.

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

Paul Sankey: Good morning, everyone.

Greg Bram: Good morning, Paul.

Paul Sankey: My congratulations to Gary. Can you just keep going a little bit with the outages? On the OPEC cuts, can you talk a little bit about the impact that you’ve been having on markets from your perspective? The Mexican explosion was another obvious one, just a commentary on how disruptive the crude market is from a buyer’s point of view right now? And I got you on Russia you seem to more or less address that already through Doug. Thanks.

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.

Paul Sankey: Got it. And then on the outages in Refining, can you talk a bit — I mean there was reports of lots of different things happening, not least because of the heat in Texas. Could you talk a bit about anything that happened with you guys in the quarter, but also how the industry perhaps was perhaps throughput was a bit distorted by various units being down and stuff?

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.

Paul Sankey : Got it. And then just finally, a quick one. The 14% you talked about wholesale up is obviously you’re taking market share. It seems to be driven by your renewable fuels, right? Is that — how do we explain the difference between your strength of sales versus the overall market being way below that?

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.

Paul Sankey : Got it. Thanks very much.

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

Ryan Todd: Great, thanks. Maybe a question on the renewable diesel side. I mean can you talk — obviously, a very strong performance in the quarter. Can you talk about sales in the quarter, which were, I mean, stronger than we had expected? Also had a very strong capture rate, which was much improved. And certainly, I think some benefit from pricing there. But can you talk about sales? What are the drivers there, implications as we look toward the back half of this year, both on sales and the kind of margin and capture on the renewable diesel side?

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.

Ryan Todd: And on the on the margin cap just had. Any general comments on what you’re seeing, I mean, headline indicators have been falling, but your capture was much improved.

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.

Ryan Todd: And maybe on a different note, with the start-up of the Port Arthur Coker and the capital rolling off from that in terms of growth CapEx, you obviously have the SAF projects underway, but what types of projects might compete for growth capital going forward? Is it more likely to be incremental SAF capacity? Are there things on the refining side that you’re looking at, whether it’s something to increase octane production or anything like that on the margin side that can compete for capital as you think about the next couple of years?

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.

Ryan Todd: Okay. Thanks, Lane.

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

Joe Laetsch: Great. Thanks everybody for taking my questions today. So I want to go back to capture rate here. So, we noticed just on the West Coast Refining margins were really strong during the quarter. Could you just touch on some of the drivers here and how we should think about the setup for the third quarter?

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.

Joe Laetsch: Great. Thanks. That’s helpful. And then just — my second one is just on OpEx and just the drivers of higher OpEx in third quarter versus 2Q. Is that on the gas side? Or how should we think about that?

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.

Joe Laetsch: Perfect. Thank you.

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

Roger Read: Good morning and congrats to everybody on there for the new roles here. I’d like to hit the diesel question a slightly different way. Last winter, we saw pretty unusually warm weather throughout Northern Hemisphere. So going back, I think you addressed this on the last call, but what do you think the missing demand was last year from a weather standpoint. And so when we think about the upcoming winter and we always just model normal weather. So, what will we potentially be looking at from a demand step up?

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.

Roger Read: Okay. That’s helpful. The other is, we have, I think somebody mentioned earlier, seeing diesel move back up over gasoline. Can you give us an idea of how you’ve run in terms of being max diesel or I should say, max distillate or max gasoline as we’ve been coming through this summer?

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.

Roger Read: Yes, NGLs are definitely help in or hurt depending on which side of the argument you’re on there. Okay. Thanks, guys.

Lane Riggs: Thanks.

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

Paul Cheng: Hi. Good morning.

Lane Riggs: Good morning, Paul.

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.

Lane Riggs: Hey, Paul, Mr. Bram is going to answer that.

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.

Paul Cheng: Actually, before we go into the capture, can I ask that how much that you can maybe further minimize on the medium sour?

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.

Paul Cheng: Okay. Understood.

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

Paul Cheng: Around North Atlantic. Yes.

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.

Paul Cheng: The Syncrude is probably was 100% — 20% at most or for your entire more than 90 input, right?

Greg Bram: No, it’s much higher than that, Paul.

Paul Cheng:

Syncrude:

Greg Bram: Yes. So our Quebec refinery runs a combination of Canadian crudes and then waterborne crudes that we bring up from the Gulf Coast.

Paul Cheng: Okay. Great. Thanks a lot.

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

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?

Richard Walsh: This is Rich Walsh. I can talk of, I guess, a little bit about the EPA decision. And then when it comes to pricing, I’ll hand it back off to Eric. I mean, we don’t have any small refinery exemptions in play. And so it’s a bit of a non-factor for us. I mean really not a lot more to share on it in that regard.

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.

Nitin Kumar: Sorry, what I was actually referring to is on your commercial side, whether you were seeing any improved demand for ethanol because those that don’t have the exemption. I guess I’ll ask a different question as well. Just on the sustaining CapEx, you mentioned $1.5 billion for this year. Are you seeing anything on the regulatory front that could increase that or increase the intensity of your sustaining CapEx in the future thinking of things like stringent particle emission standards or anything like that?

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.

Nitin Kumar: Thank you

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

Neil Mehta: Yeah. Good morning, team and Lane, Gary and Joe, if you’re on the line. Congratulations to each of you. And that’s kind of where I want to start. I mean, Lane, that over the last couple of years, the strategic vision has been very clear and consistent. We would just love your perspective as you step into this new role. What are the two or three things that you’re most focused on to take Valera to the next level?

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.

Neil Mehta: Thanks, Lane. And then the follow-up is just around return of capital. And just maybe you could provide an update. It was another quarter where you were able to return cash in excess of sort of the brackets that you talked about historically. And how are you thinking about with the stock having done well here more recently, continuing to lean into the buyback versus reinvest back in the business and talk about the dividend as well.

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.

Operator: The next question is coming from Jason Gabelman of Cowen. Please go ahead.

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.

Eric Fisher: Yeah, this is Eric. On the RIN prices, the EPA held the ethanol requirement of 15 billion gallons, which as we’ve seen over the last several years, it’s beyond the blend wall, which means the D4 RIN will be used to fulfill that obligation. Given our outlook, we don’t see a big change in RINs. RIN prices or RIN supply you see that as relatively business as usual.

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?

Eric Fisher: Yes. If you — we’re not going to speak on everyone else’s projects, but we do see that a lot of the R&D projects are taking longer to come up and their projects are being slowed down. So our outlook is the expected growth curve of R&D is not going to be as aggressive as a lot of predictions.

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.

Gary Simmons: Yes, Jason, this is Gary. I don’t know that we can see that the warmer weather has caused a significant change in diesel demand. I think where inventories are low in the United States, we’re seeing the same thing globally. Low diesel inventories and a pull from the United States into — especially into Europe, very high as a result of low inventory globally. Moving forward, I don’t know really where the path is in terms of restocking the inventory. You look — we’re 35 million barrels below the five-year average. Last year at this time, we were 35 million barrels below the five-year average. So we really aren’t making it dent in it. If you look going forward, yes, there’s no refined capacity coming online, but — when you look at the stated nameplate capacity, that new refining capacity and you look at the estimates of global oil demand growth, it doesn’t look like a significant impact on the supply-demand balances going forward.

Jason Gabelman: Great. Thanks for the color.

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

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?

A – Lane Riggs: Yes, I think you’ve got that surrounded. The one thing I would add is when you go to a carbon intensity basis for the PTC, that will advantage Diamond Green Diesel because we run the lowest CI feedstocks. So whatever the PTC becomes, we will still have the highest capture of PTC versus our peers. So there’s no doubt that it becomes a fraction of $1 based on CI but we’ll still have the most advantaged platform.

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?

A – Lane Riggs: Yes. I think — yes, that’s a lot of questions there. Well, what I would say is — so the first question of is there a pathway to take ethanol into jet fuel. The answer is yes, post sequestration. That is — it does allow ethanol to become a viable feedstock into that market. It’s way too early to talk about numbers and capital and all of that from a from a project standpoint. But if you look at it from the airline standpoint, they do see that the first barrel of SAF that they will get ratably will be RD based. There is — as that conversion goes through the RD markets, the next barrel could be from an ethanol source. But that’s like you said, that’s much further out there on the time line. So yes, and then if you look at in terms of — is the technology there?

And is there a capability there and will airlines differentiate between the two? Again, probably too soon to tell. But from a fuel standpoint, there’s no difference between an ethanol-based barrel versus an RD based barrel from a SAF standpoint. But a lot of work to be done first on how RD will price SAF into the market, and then these are all much, much further down the time line.

Q – Matthew Blair: Understood. Thanks for your comments.

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

Operator: Ladies and gentlemen, thank you for your participation. This concludes today’s event. You may disconnect your lines at this time and enjoy the rest of your day.