Valero Energy Corporation (NYSE:VLO) Q1 2023 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q1 2023 Earnings Call Transcript April 27, 2023

Valero Energy Corporation beats earnings expectations. Reported EPS is $8.27, expectations were $7.23.

Operator: Greetings, and welcome to the Valero First Quarter 2023 Earnings Conference Call. . It is now my pleasure to introduce your host, Homer Bhullar, Vice President of Investor Relations. Thank you. You may begin.

Homer Bhullar: Good morning, everyone, and welcome to Valero Energy Corporation’s First Quarter 2023 Earnings Conference Call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero’s senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.

I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company’s or management’s expectations or predictions of the future are forward-looking statements intended to be covered by safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we’ve described in our earnings release and filings with the SEC. Now I’ll turn the call over to Joe for opening remarks.

Joseph Gorder: Thanks, Homer, and good morning, everyone. We had another strong quarter with all of our segments performing well. Our refineries operated at 93% capacity utilization rate despite planned maintenance at several facilities. Our ability to optimize and maximize system throughput while undertaking maintenance activities illustrates the benefits from our long-standing commitment to operational excellence. Refining margins were supported by lower industry refining capacity in a backdrop of strong product demand. I’m also proud to report that the Port Arthur coker project was completed in March and successfully started up in early April, which is a testament to the strength of our engineering and operations teams. The project is expected to increase the refinery’s throughput capacity and ability to process incremental volumes of sour crude oils and residual feedstocks while also improving turnaround efficiency.

Our Renewable Diesel segment set another sales volume record in the first quarter, with the continued ramp-up of DGD Port Arthur, which was started up in November 2022. In January, we announced that DGD approved a sustainable aviation project at Port Arthur, Texas. The DGD Port Arthur plant will have the capability to upgrade approximately 50% of its current 470 million-gallon annual renewable diesel production capacity to sustainable aviation fuel or SAF. The project is expected to be completed in 2025 and is estimated to cost approximately $315 million, with half of that attributable to Valero. With the completion of this project, DGD is expected to be 1 of the largest manufacturers of SAF in the world. In the Ethanol segment, BlackRock and Navigator’s carbon sequestration project is progressing, and they expect to begin start-up activities in late 2024.

We expect to be the anchor shipper with 8 of our ethanol plants connected to this system which will allow us to produce a lower carbon-intensity ethanol product and significantly improve the margin profile and competitive positioning of our Ethanol business. And we continue to advance other low-carbon opportunities, such as renewable hydrogen, alcohol to jet and additional renewable naphtha and carbon sequestration projects. All of our projects must meet a minimum return threshold to continue to progress through our gated review process. On the financial side, we continue to strengthen our balance sheet, reducing debt by $199 million in the first quarter and ending the quarter with a net debt to capitalization ratio of 18%. In January, we announced an increase in our quarterly dividend on our common stock from $0.98 per share to $1.02 per share, demonstrating our long-standing commitment to stockholder returns.

Looking ahead, we expect refining fundamentals to remain supported by low global light product inventories, tight product supply and demand balances and continued increase in product demand as we approach peak air travel and summer driving season. In closing, our team continues to successfully execute a strategy that enables us to meet the challenge of supplying the world’s need for reliable and affordable energy in an environmentally responsible manner. The tenets of our strategy, underpinned by operational excellence, deploying capital with an uncompromising focus on returns and honoring our commitment to stockholders have been in place for nearly a decade and continue to position us well for the future. So with that, Homer, I’ll hand the call back to you.

Homer Bhullar: Thanks, Joe. For the first quarter of 2023, net income attributable to Valero stockholders was $3.1 billion or $8.29 per share compared to $905 million or $2.21 per share for the first quarter of 2022. First quarter 2023 adjusted net income attributable to Valero stockholders was $3.1 billion or $8.27 per share compared to $944 million or $2.31 per share for the first quarter of 2022. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying earnings release tables. The Refining segment reported $4.1 billion of operating income for the first quarter of 2023 compared to $1.5 billion for the first quarter of 2022. Refining throughput volumes in the first quarter of 2023 averaged 2.9 million barrels per day, which was 130,000 barrels per day higher than the first quarter of 2022.

Throughput capacity utilization was 93% in the first quarter of 2023 compared to 89% in the first quarter of 2022. Refining cash operating expenses were $4.78 per barrel in the first quarter of 2023, lower than guidance of $4.95, primarily attributed to higher throughput and lower natural gas prices. Renewable Diesel segment operating income was $205 million for the first quarter of 2023 compared to $149 million for the first quarter of 2022. Renewable diesel sales volumes averaged 3 million gallons per day in the first quarter of 2023, which was 1.3 million gallons per day higher than the first quarter of 2022. The higher sales volumes in the first quarter of 2023 were due to the impact of additional volumes from the start-up of the DGD Port Arthur plant in the fourth quarter of 2022.

The Ethanol segment reported $39 million of operating income for the first quarter of 2023 compared to $1 million for the first quarter of 2022. Ethanol production volumes averaged 4.2 million gallons per day in the first quarter of 2023, which was 138,000 gallons per day higher than the first quarter of 2022. For the first quarter of 2023, G&A expenses were $244 million and net interest expense was $146 million. Depreciation and amortization expense was $660 million, and income tax expense was $880 million for the first quarter of 2023. The effective tax rate was 22%. Net cash provided by operating activities was $3.2 billion in the first quarter of 2023. Excluding the unfavorable change in working capital of $534 million in the first quarter and the other joint venture member share of DGD’s net cash provided by operating activities excluding changes in DGD’s working capital, adjusted net cash provided by operating activities was $3.6 billion.

Regarding investing activities, we made $524 million of capital investments in the first quarter of 2023, of which $341 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance, and $183 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD, capital investments attributable to Valero were $467 million in the first quarter of 2023. Moving to financing activities. We returned over $1.8 billion to our stockholders in the first quarter of 2023, of which $379 million was paid as dividends and $1.5 billion was for the purchase of approximately 11 million shares of common stock, resulting in a payout ratio of 52% of net cash provided by operating activities.

With respect to our balance sheet, as Joe mentioned, we completed additional debt reduction transactions in the first quarter that reduced Valero’s debt by $199 million through opportunistic open market repurchases. We ended the quarter with $9 billion of total debt, $2.4 billion of finance lease obligations and $5.5 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was 18% as of March 31, 2023. And we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments.

About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modeling our second quarter operations, we expect Refining throughput volumes to fall within the following ranges: Gulf Coast at 1.73 million to 1.78 million barrels per day; Mid-Continent at 405,000 to 425,000 barrels per day; West Coast at 250,000 to 270,000 barrels per day; and North Atlantic at 450,000 to 470,000 barrels per day. We expect Refining cash operating expenses in the second quarter to be approximately $4.60 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 per gallon, which includes $0.19 per gallon for noncash costs such as depreciation and amortization.

Our Ethanol segment is expected to produce 4.2 million gallons per day in the second quarter. Operating expenses should average $0.40 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the second quarter, net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $670 million. For 2023, we expect G&A expenses, excluding corporate depreciation, to be approximately $925 million. That concludes our opening remarks. .

Q&A Session

Operator: . Our first question is coming from the line of Manav Gupta with UBS.

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

Joseph Gorder: No, Manav, we’re happy to do that, and thanks for your comments. Gary, do you want to give them some insight?

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

Operator: Our next question is coming from the line of Theresa Chen with Barclays.

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

Lane Riggs: Yes, this is Lane. some general comments about capture rates, sort of compare our first quarter capture rate to our second quarter capture rate. Holding all things equal, we’ll blend less butane. So everything — pulling everything equal, our capture rate will actually fall just due to butane. And then as you alluded to, you look at feedstocks, what’s the trajectory of feedstocks, they’re lower. On the other side of it, we’re seeing big RBOB premiums versus CBOB. So to the extent that, that’s not captured in our capture rate, that’s actually a positive. So there are several things you just got to look at. And what you got to focus on are the — some of the drivers that may not be in our formula for our crack attainment and how those change relative to things those are tied to. An example would be Maya versus WCS or, like I said, RBOB versus CBOB. Those are the things you guys kind of key on trying to predict maybe how our crack attainment looks.

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

Lane Riggs: Well, I’ll start on at least our system and let Gary kind of look at — talk about the supply. The start-up of our Port Arthur Coker goes a long way to shoring up our VGO position. Essentially, that’s where it is. It’s taking resid and heavier crudes and cracking into sort of — in the distillate and essentially a VGO boiling range material. So it allows us to sort of — our requirement for importing VGO has fallen post the new coker startup.

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

Operator: Our next question is coming from the line of Doug Leggate with Bank of America.

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

Gary Simmons: Yes. So I’ll go through. We have seen — during the first quarter, we saw the supply-demand balances around heavy sour get tighter. Some of it is supply. You also see — saw Chinese refinery utilization ramp-up, which put more demand in the system. But going forward, I think there are some bullish factors. Platts is reporting 500,000 barrels a day. Canadian crude production is off-line due to maintenance. We’ll get that production back. Venezuelan production is forecasted to grow. And our view is that more Chevron production from that region will make its way into the Gulf as we progress through the year. At some point in time, all indications are that the Lyondell refinery will come down, which will kick more heavy sour back to the market.

And then if the demand and — the supply-demand balances that are currently being forecasted are correct, at some point in time, you’ll need that OPEC production back on the market, which again is bullish to differentials.

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

Gary Simmons: Yes, I really can’t make a comment. We don’t have a lot of insight into either one of those refineries.

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

John Royall: Just wanted to start on the return of capital side. You guys returned above your 40% to 50% range again this quarter, I think second quarter in a row. What’s your latest thinking on where you want to be in that range of returns to shareholders given your balance sheet is very strong, but fundamentals appear to be ticking down and you can see that in your indicators.

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

John Royall: Great. And then I was hoping you could also touch on the regulatory changes out in California and how you expect those to play out and the potential impact on both your business and maybe just the broad refining market in California.

Richard Walsh: This is Rich. I can start out with just sort of the regulatory climate. California has always been a tough regulatory climate for operations. And so I’m assuming you’re talking about the California 2 rulemaking that’s out there. And what we would just say is that the bill does have some burden, some reporting requirements in it. And then obviously, it kicks basically a profit tax over to this California Energy Commission to implement it. And so we’ll stay active and engaged in that rulemaking process and watch what develops out of the agency there. It’s unclear what price cap, if any, they’ll ultimately put in place. I would point out that the rulemaking on that, the standard that the agency is supposed to use is they’re supposed to determine that the benefits to consumers are outweighed by the potential cost to consumers.

And it goes without saying that attempts by governments to artificially limit commodity prices has never been really good for the economy and it ultimately ends up hurting consumers. So we’ll just have to see how that all plays out.

Joseph Gorder: And John, this is Joe. Just let me bolt on something to what Rich said. So it’s — we have a great team operating both of our refineries on the West Coast. Great teams are running those plants. And we have been very consistent and clear in our approach to the California business. That is we aggressively manage the capital, we invest to maintain safe and reliable operations out there, but we haven’t invested capital in growing that business for many years now. Now historically, California, in a normal operating environment, isn’t a strong contributor to our earnings. We’ve always viewed it as an option on periodically strong margins. And if the margin caps are set at levels that remove the upside, the opportunity to earn a return isn’t there the way it’s been in the past and we’ll have to evaluate our options.

Right now, Rich and his team are communicating to the California Energy Commission and others the concerns that we have, and we’re just going to have to wait and see what happens out there. So it is an environment that is a difficult operating environment. I would not even take a shot at stating what might happen to the overall refining environment out there, but I can just tell you that from our perspective, we’re just going to have to watch it and see and then we’ll evaluate our options.

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

Paul Sankey: Could you repeat the wholesale sales demand number that you just gave and explain how come, if I heard you right, that’s growing so massively.

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

Paul Sankey: So there’s no structural change. It’s just better wholesale performance?

Gary Simmons: Yes. Okay. I’m not counting that as a question, Joe.

Joseph Gorder: Paul, we could talk all day.

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

Richard Walsh: Well, this is Rich Walsh again. I guess I’ll take an effort to respond on that in terms of — I think you’re probably alluding to some negotiations that are going on right now. And just this morning, I think the Republican bill has been revised to include some of the credits to be back in that they were proposing to pull out. And so we’re looking at the clean energy tax credits being put back in, and so the things that help us on our renewable side and some of our sequestration projects back in. And they also have grandfathered those that have already made investment decisions on the while SAF is out, the projects that have been announced on SAF are back in. So that means our projects would be still eligible for the proper treatments on that.

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

Gary Simmons: Yes, Paul, our view is whenever inventory is as low as it is today, it just puts you way out on the margin curve where the slope is really steep and any type of market news can have a significant impact on prices and margins. So early in the year, the market headlines were all about losing Russian supply with the ramp-up in sanctions and it drove the market up. Today, I think people are generally comfortable that the Russian barrels will continue to flow and then a lot of concern on the economy and what happens with demand in the future. As I’ve said, we’re not seeing any indication of demand weakness today, but I think that’s a concern is what happens in the future.

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

Roger Read: Yes, I’d like to follow up, Joe — I’d like to follow up on the Comments or how you’re looking at the diesel and gasoline markets. I mean there’s a ton of ways to track demand and shortfalls of supply. But one we pay attention to is each end of the Colonial pipeline, and it shows clear stress in the gasoline market. So I guess I’d like to dig into maybe what you see in the Atlantic Basin, particularly between New York and Northwest Europe in terms of just outright gasoline supply. Or is it a component issue? Or what exactly is going on there?

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

Roger Read: Yes. I mean it’s early in the quarter, but really haven’t seen the gap quite this large at this time of the year before. So it definitely shows stress. Follow-up question, if I could, on the SAF. Obviously, you mentioned there are some opportunities in terms of what’s moving forward legislatively. If you weren’t to see, let’s call it, fundamental support for SAF margins, do you want to make SAF? I mean, what’s the driver to do that versus renewable diesel which obviously already enjoys support as well as LCFS programs.

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

Operator: The next question is coming from the line of Ryan Todd with Piper Sandler.

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

Unidentified Company Representative: Well, I think — this is Eric again. In particular, we’ll start with ethanol to jet. Assuming the Navigator project goes forward, that will lower the carbon intensity of our ethanol to a point where it will qualify as a feedstock into SAF. And so if you look at that as the precursor project that would then enable an ethanol to jet SAF project, that’s one of the things we’re looking at. Now that’s years out from anything we would talk about in any sort of detail, but conceptually that’s kind of what would line up that possibility from a project standpoint. And then renewable hydrogen, that’s another sort of horizon opportunity, that as you look at your low-carbon platforms, if you can make blue or green hydrogen, it’s just another way to further lower your CIs on your low carbon operations.

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

Lane Riggs: Yes, this is Lane. So we started it up on April 5. I would say actually, this week, we’ve sort of ramped up most of the refinery up to where we’re running. We’re close to fuel to full. We’re sort of from now through the rest of the quarter, you will see the benefit of . Clean start-up, as Joe alluded to earlier in his comments. It was done really well by our team. It’s working just as we had indicated. In terms of the contribution on EBITDA, when you take sort of the current volumetrics and use forward pricing on it, it’s normally about $0.5 billion a year is the benefit.

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

Jason Gabelman: I wanted to ask one on market structure. I think there’s some concern because there’s headlines around Asia cutting refining runs because margins are low there and there’s some concern that, that could permeate into the U.S. And so the question is, how should the market kind of take that indicator? Should they think that while Asia margins are falling and so U.S. will follow because there’s global weakness? Or conversely, because Asia margins are falling, U.S. cracks are around the level they are, probably closer to a floor, because of the structural kind of tailwinds that are out there and Asia is kind of absorbing all of the throughput declines related to global demand issues? I know it’s a bit of a complex question, but I guess, give it a shot.

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

Jason Gabelman: Okay. That’s helpful. And then the follow-up on DGD. Where are we in terms of the DGD distribution? Have you received one yet? Is that coming soon? And how are you thinking about that cash being moved up to the partners moving forward?

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

Jason Gabelman: Okay. Any idea around the quantity?

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

Operator: Our next question is coming from the line of Matthew Blair with Tudor, Pickering, Holt.

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

Lane Riggs: So Matt, this is Lane. I’ll start out with the first part of it. So the things that are contributing factors were we had backwardation sort of flattened out in the market on feedstock. That’s always one you get. So market structure plays into capture rates in a big way. So it’s tightened out some. You had wider differentials in the first quarter versus the fourth quarter on all the crudes that we run. And then finally, there were pretty good jet premiums versus distillate in the first quarter. Those — those are the other things driving our capture rate. With respect to the other on mentioned…

Joseph Gorder: I don’t think the RIN had anything to do with it.

Gary Simmons: And I wouldn’t say exports had any kind of material impact on capture rates either.

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

Lane Riggs: Yes, we — this is Lane. We have a policy of not really commenting directly on our turnaround activity, but I would just take the guidance to be kind of where we think it’s going to be.

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

Operator: We have no additional questions at this time. So I’ll pass the floor over to management for any additional closing remarks.

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

Operator: Ladies and gentlemen, this does conclude our call and webcast. You may disconnect your lines at this time. We thank you for your participation.