Valero Energy Corporation (NYSE:VLO) Q4 2022 Earnings Call Transcript

Valero Energy Corporation (NYSE:VLO) Q4 2022 Earnings Call Transcript January 26, 2023

Operator: Greetings and welcome to the Valero’s Fourth Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations. Thank you, Mr. Bhullar. You may begin.

Homer Bhullar: Good morning everyone and welcome to Valero Energy Corporation’s fourth quarter 2022 earnings conference call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero’s senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.

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

Joe Gorder: Thanks Homer and good morning everyone. We finished the year strong with our refineries operating at 97% capacity utilization in a favorable refining margin environment. In fact, this is the highest refinery utilization for our refining system since 2018. I’m also proud to share that 2022 was the best year ever for combined employee and contractor safety, which is a testament to our long-standing commitment to safe, reliable, and environmentally responsible operations. As we saw during most of 2022, refining margins were supported by low product inventories, which resulted from the significant permanent global refinery shutdowns and the continued recovery in product demand. Our refining system also benefited from heavily discounted sour crude oils and fuel oils.

These discounts were driven by increased sour crude oil supply, high freight rates, and the impact from the IMO 2020 regulation for lower sulfur marine fuels. Also, high natural gas prices in Europe incentivize European refiners to process sweet crude oils in lieu of sour crude oils, adding further pressure on sour crude oils. And our refining projects that are focused on reducing cost and improving margin capture remain on track. The Port Arthur Coker project is expected to be completed in the second quarter of 2023 and will increase refinery’s throughput capacity and ability to process incremental volumes of sour crude oils and residual feedstocks while also improving turnaround efficiency. In our Renewable Diesel segment, we continue to expand operations, and we set another sales volume record in the fourth quarter with the successful commissioning and start-up of the new DGD Port Arthur renewable diesel plant in November.

That project was completed under budget and ahead of schedule and brings DGD’s annual production capacity to approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. In the Ethanol segment, BlackRock and Navigators carbon sequestration project is still progressing on schedule and is expected to begin start-up activities in late 2024. We expect to be the anchor shipper with eight of our ethanol plants connected to this system, which is expected to result in the production of a lower carbon intensity ethanol product that should significantly improve the margin profile and competitive positioning of the business. And we continue to advance other low-carbon opportunities such as sustainable aviation fuel, renewable hydrogen and additional renewable naphtha and carbon sequestration projects.

Our gated process helps ensure these projects meet our minimum return threshold. On the financial side, we continue to strengthen our balance sheet, paying off all of the incremental debt incurred during the pandemic and ending the year with a net debt to-capitalization ratio of 21%. Looking ahead, we expect low product inventories and continued increase in product demand to support margins, particularly for US coastal refiners that have crude oil supply and natural gas advantages relative to global refineries. And we continue to see large discounts for heavy sour crude oils and fuel oils that we can process in our system. The startup of the Port Arthur Coker is also expected to have a significant earnings contribution in the back half of 2023, supported by wide sour crude oil differentials and strong diesel margins.

In closing, we’re encouraged by the refining outlook, which, coupled with the contribution from our strategic growth projects in refining and renewable fuels, should continue to strengthen our long-term competitive advantage and shareholder returns. So with that, Homer, I’ll hand the call back to you.

Homer Bhullar: Thanks, Joe. For the fourth quarter of 2022, net income attributable to Valero stockholders was $3.1 billion or $8.15 per share, compared to $1 billion or $2.46 per share for the fourth quarter of 2021. Fourth quarter 2022 adjusted net income attributable to Valero stockholders was $3.2 billion or $8.45 per share compared to $988 million or $2.41 per share for the fourth quarter of 2021. For 2022, net income attributable to Valero stockholders was $11.5 billion or $29.04 per share compared to $930 million or $2.27 per share in 2021. 2022 adjusted net income attributable to Valero stockholders was $11.6 billion or $29.16 per share compared to $1.2 billion or $2.81 per share in 2021. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables.

The Refining segment reported $4.3 billion of operating income for the fourth quarter of 2022 compared to $1.3 billion for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $4.4 billion compared to $1.1 billion for the fourth quarter of 2021. Refining throughput volumes in the fourth quarter of 2022 averaged 3 million barrels per day. Throughput capacity utilization was 97% in the fourth quarter of 2022. Refining cash operating expenses of $5 per barrel in the fourth quarter of 2022 were $0.14 per barrel higher than the fourth quarter of 2021, primarily attributed to higher natural gas prices. Renewable Diesel segment operating income was $261 million for the fourth quarter of 2022, compared to $150 million for the fourth quarter of 2021.

Photo by Jason Blackeye on Unsplash

Renewable Diesel sales volumes averaged 2.4 million gallons per day in the fourth quarter of 2022, which was 851,000 gallons per day higher than the fourth quarter of 2021. The higher sales volumes were due to the impact of additional volumes from the DGD St. Charles plant expansion and the fourth quarter 2022 start-up of the DGD Port Arthur plant. The Ethanol segment reported $7 million of operating income for the fourth quarter of 2022, compared to $474 million for the fourth quarter of 2021. Adjusted operating income for the fourth quarter of 2022 was $69 million compared to $475 million for the fourth quarter of 2021. Ethanol production volumes averaged 4.1 million gallons per day in the fourth quarter of 2022. The higher operating income in the fourth quarter of 2021 was primarily attributed to multi-year high ethanol prices due to strong demand and low inventories.

For the fourth quarter of 2022, G&A expenses were $282 million and net interest expense was $137 million. G&A expenses were $934 million in 2022. Depreciation and amortization expense was $633 million and income tax expense was $1 billion for the fourth quarter of 2022. The annual effective tax rate was 22% for 2022. Net cash provided by operating activities was $4.1 billion in the fourth quarter of 2022 and $12.6 billion for the full year. Excluding the unfavorable change in working capital of $9 million in the fourth quarter and $1.6 billion in 2022 and the other joint venture member share of DGD’s net cash provided by operating activities, excluding changes in DGD’s working capital, adjusted net cash provided by operating activities was $4 billion for the fourth quarter and $13.8 billion for the full year.

Regarding investing activities, we made $640 million of capital investments in the fourth quarter of 2022, of which $349 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $291 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD and those related to other variable interest entities, capital investments attributable to Valero were $538 million in the fourth quarter of 2022 and $2.3 billion for the year, which is higher than our annual guidance primarily due to project spend timing on the Port Arthur Coker project and the accelerated completion of the DGD Port Arthur plant. Moving to financing activities.

We returned $2.2 billion to our stockholders in the fourth quarter of 2022 and $6.1 billion in the year, resulting in a 2022 payout ratio of 45% of adjusted net cash provided by operating activities through dividends and stock buybacks. With respect to our balance sheet, we completed additional debt reduction transactions in the fourth quarter that reduced Valero’s debt by $442 million through opportunistic open market repurchases. As Joe noted earlier, this reduction, combined with a series of debt reduction and refinancing transactions since the second half of 2021, have collectively reduced Valero’s debt by over $4 billion. We ended the year with $9.2 billion of total debt, $2.4 billion of finance lease obligations and $4.9 billion of cash and cash equivalents.

The debt-to-capitalization ratio, net of cash and cash equivalents was approximately 21%, down from the pandemic high of 40% at the end of March 2021, which was largely the result of the debt incurred during the height of the COVID-19 pandemic. And we ended the year well capitalized with $5.4 billion of available liquidity, excluding cash. Turning to guidance. We expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and $500 million to growth. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.59 million to 1.64 million barrels per day; Mid-Continent at 415,000 to 435,000 barrels per day; West Coast at 245,000 to 265,000 barrels per day; and North Atlantic at 415,000 to 435,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be approximately $4.95 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 non-cash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 4 million gallons per day in the first quarter. Operating expenses should average $0.51 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the first quarter, net interest expense should be about $130 million and total depreciation and amortization expense should be approximately $655 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 to questions, please adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. Please respect this request to ensure other callers have time to ask their questions.

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Q&A Session

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

Theresa Chen: Good morning, everyone. Thank you for taking my questions.

Joe Gorder: Good morning, Theresa.

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

Gary Simmons: Theresa, this is Gary. I think, initially, we felt like even with the ramp-up in sanctions, you would just see a rebalancing of trade flows much like we saw with crude and resids. Most people in the trade today think that the sanctions will actually result in a reduction in Russian refinery utilization, and you’ll see lower exports of VGO and diesel coming out of Russia when the sanctions take place.

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

Gary Simmons: Yes. So the market is very, very tight. We’re looking at total light product inventories 55 million barrels below the five-year average. And so typically, this is a period of time where you see restocking take place. And with the winter storm outage and high maintenance activity, we just haven’t been able to restock inventories which sets the year up very nicely in terms of refinery margin perspective.

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

Theresa Chen: Thank you.

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

Doug Leggate: Hi, good morning, everyone. Thanks for taking my questions. Happy New Year, guys for those I haven’t spoken to you yet.

Joe Gorder: Thanks, Doug.

Doug Leggate: Joe, I don’t know who you want to direct this too, but I’m curious about coker economics. When you laid out the original plan to bring this online, we were in a very different diesel resid market than we are today. So could you — as you see the earnings power of that facility as it stands, maybe at strip or however you want to characterize it, can you give us an idea what your expectations are relative to what it looked like when you first set out the project? And I’ve got a follow-up, please.

Joe Gorder: Yes. No, Doug, we’ll let Lane take a crack at this one.

Lane Riggs: Hi, Doug. I hope you’re all right. It’s — so just to remind everybody, our FID, I think, was $325 million, that’s sort of based on mid-cycle. We sort of look back at it in sort of 2018, I think the EBITDA was around $420 million. If you sort of fourth quarter, it’s in the order of probably $700 million, maybe a little bit more dollars. So if you use those kind of margins. So obviously, it’s — I don’t know if we have incredible foresight, but it’s great to be lucky. And we lucky to be good, that’s exactly right. So yes, I’d say have assuming all this holds, and I think, at least for our outlook, at least for this year, is that the sort of resid prices and distillate cracks a whole, it will be a — the timing is pretty perfect.

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

Lane Riggs: I’m going to be fairly specific right here. We’re going to be mechanically complete somewhere late Feb, early March, and we expect oil in somewhere late April or early May.

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

Joe Gorder: Yes. No, Doug, that’s a very fair question and we’ll let Jason share his strategy around this.

Jason Fraser: Yes, I’ll give a little context quarter, we did beat a goal, which will kind of change in how we look at things. So, back prior to the pandemic, we were frequently at the high end or even above our target return payout range of 40% to 50%. Now, during the pandemic, we were very committed to our dividend and paying the dividend loan put us way above our 40% to 50% target range. And as you know, during COVID, we had to take on another $4 billion of debt in 2020. So, one of our main objectives as the financial situations improve post-COVID was the payback this incremental debt, which we’ve been aggressively working on. And we’ve messaged that while we’re working on this competing goal of deleveraging, we would stay at the lower end of our 40% to 50% payout range, which is what we’ve been doing.

Now, in the fourth quarter, we were able to repurchase $442 million of debt, which is the final step in us meeting our goal of deleveraging by $4 billion. So, with that insight, during the quarter, we increased our stock purchases to $1.8 billion and we’re able to end the year at a 45% payout ratio. So, we’re able to work our way back to the midpoint of our target range for the full year. And now that we’ve paid off our pandemic debt and build our cash balance up to a good level, you should reasonably expect us to be looking at mid-level or higher payout targets given the construction margin environment as we move forward. Now, on the dividend side, please go ahead — yes, you’d asked about dividend too, which is other pieces of the puzzle.

So, we continue to aim for a dividend as sustainable and competitive versus our peers. We would also like to show growth. And as you know, the dividends — we hadn’t had any growth since the first quarter of 2020 because, first of all, we had the pandemic, which we had to work our way through. And then we’re rebuilding cash and working our debt down. So, now, as I’ve said, we’ve kind of met those goals so we would like to return to a pattern of growth as we move forward.

Doug Leggate: I appreciate the full answer, Jason. As you know, Joe, we’d like to see cash on the balance sheet. So, thanks so much for that. All the best.

Joe Gorder: Net zero debt, Doug.

Doug Leggate: Thank you everybody.

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

Roger Read: Yes, good morning. I guess I’d like to jump in here on just, call it, crude structure in the market, right? We had big SPR releases a lot of last year. Those seem to have at least, I don’t know if I’d say ceased, they’ve definitely eased quite a bit. You mentioned the Russian sanctions coming up. That’s really more of a product thing. And then we’ve had the Venezuelan barrels start to enter the Gulf of Mexico. So, I guess as a broad question, how are you looking at crude availability and crude dips as we get into the early days of 2023 here?

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

Roger Read: And as a follow-up on that, I think, Joe, you mentioned with the Russian ban, we might see less VGO in the market. Maybe, Gary, those were your comments. If there’s less VGO in the Atlantic Basin in general, what is your expectation for substitute feedstock into the summer of the secondary units and the kind of follow-on impacts on distillate production?

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

Roger Read: Great. I’ll €“ that’s my two, so I’ll leave it there. Thank you.

Lane Riggs: Thanks, Roger.

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

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

Gary Simmons: Yeah. So this is Gary. I think we’ve certainly seen the Chinese more active in the market, both purchasing feedstocks and in the product markets as well. It looks to us like a lot of the product exports from China are staying in the region, although we occasionally see some exports making their way into our market. But our view is that, you’ll see significant demand recovery in China by the second quarter. And a lot of that ramp-up in refinery utilization in China will be needed to supply the domestic demand. On the new refinery capacity, at least our supply-demand balances still show year-over-year demand will outpace capacity additions. And so we’re not too concerned about it. A lot of that capacity really doesn’t make a lot of transportation fuels. Some of the big refineries in China, it’s less than 50% total gasoline, jet and diesel yield, a lot more petrochemicals and fuel oil production.

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

Eric Fisher: Yeah, this is Eric. We haven’t really seen a big change in feedstock costs with DGD 3 coming on. As you said, we did see a big change where waste oil feeds really equilibrated to soybean oil with DGD 2 in 2021. But with the start-up of DGD 3, we’ve seen prices hold pretty flat. We saw that soybean oil actually, at least CBOT €œsoybean oil€, came pretty flat to waste oils in October and November. But then we saw the €œsoybean oil€ drop really with the EPA announcement on their RFS obligations for the next three years. And so €“ but overall, to answer your question, we haven’t seen a big change in feedstock prices. It’s been pretty stable.

John Royall: Thank you.

Operator: Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please go ahead.

Sam Margolin: Good morning. Thank you.

Joe Gorder: Good morning, Sam.

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

Lane Riggs: I’ll start and if Gary wants to sort of add. This is Lane, by the way, Sam. So natural gas still at the UK and really in the Netherlands is still nominally around $20 per million BTU. When comparing that today, sort of the Houston — I mean probably nominally three and change. So there’s still a significant difference between natural gas cost now. With that said, we’ll use our Pembroke refinery as a proxy. Natural gas really hasn’t driven our signals in over a year. And so I guess what I’m saying now we don’t have an SMR and we’re not — we don’t have a big hydrocracker, so we don’t have a lot of insight into how that flows through to their marginal economics on those units. But what I’m saying is it’s high natural gas prices. In Europe, at least for us, it hasn’t changed our signals, which is macro run max at our Pembroke refinery.

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

Lane Riggs: We like where you’re going, Sam.

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

Lane Riggs: What was that last question?

Homer Bhullar: Contribution at the plant level?

Lane Riggs: Yes. We can’t really say that. We do appreciate your comments around it. I mean — if you think about what this coker does, at least, it reduces — well, heavy the refinery up and our intermediate purchases sort of if you think about our VGO comments will be down significantly. So the better integrates sort of vertically integrates that refinery and makes it way less sort of, as you said, it’s a very important asset. It makes us way less, I’d say, significantly less dependent on intermediates to fill out the refinery.

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

Sam Margolin: All right. Well, thanks so much. Have a great day

Joe Gorder: You too.

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

Paul Cheng: Hey, guys. Good morning.

Joe Gorder: Good morning.

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

Lane Riggs: So are you talking about the turnaround portion of it? Are you just–?

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

Lane Riggs: That’s what I’ve alluded to a little bit–

Paul Cheng: But I’m more interested if it is not doing the turnaround, how the new coker addition will impact in terms of your , your product, yield and your overall throughput?

Lane Riggs: So, as I said to Sam, it’s — we’ll heavy up considerably. Today, we run some light and medium crudes. You’ll see us run significantly more heavy, maybe plus rate, probably over time. I’d looking back at the FID some, but it’s not as much as you would think. And in terms of distillate, that’s really the net product we make out of this, and it’s sort of a plus 15% to plus 25% depending on the crude die in terms of distillate. What it really is, is a reduction in feedstock purchases for us. In addition to like we said, it’s a turnaround efficiency.

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

Lane Riggs: I’m sorry, Paul, can you repeat that?

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

Lane Riggs: No, we’re not increasing 50,000 barrel per day. We’re heavying up. You’ll see our rates. I don’t normally go from — I don’t know if it’s public here, I got to be careful. We run anywhere from 340 to 360 today, 375, depending on the crude die. I think we could potentially go up plus 30 to plus 40 on crude depending on how heavy we are or light we are. So, that’s sort of what happens. And so then it just changes. When we do this all the time whenever we change our crude die, we sort of have to spot in intermediate purchases to finish our conversion units out. So, what will happen is we’ll reduce the amount of intermediate purchases depending significantly on the base and tuning the refinery between how heavy we are and how we’ll change sort of the how crude run rates. So, — but it’s not a plus 150,000.

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

Joe Gorder: Will it increase?

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

Paul Cheng: And second question is that in your North Atlantic, the margin in this quarter is really, really strong, even comparing to the benchmark indicator. Can you maybe help us better understand that what may be some driver outside just the market conditions? Yes, any?

Lane Riggs: So Paul, which margin — Valero’s overall–

Paul Cheng: North Atlantic — your North Atlantic?

Lane Riggs: Well, I didn’t really — it’s not that much stronger versus the prior quarter. I mean, just the way we look at it is

Paul Cheng: North Atlantic we see — I think $29.

Lane Riggs: No, but I’m saying versus prior like I said.

Homer Bhullar: Capture was only up a margin.

Lane Riggs: Yeah. Capture rate was up just a little bit.

Paul Cheng: Okay. Thank you.

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

Ryan Todd: Thanks. Maybe €“ a follow-up on some things that you maybe touched on a little bit earlier on the call. I think from a macro point of view, as some of the €“ what appear to be at least whether they’re structural or lingering improvements and kind of underlying profitability for the business. It seems like the global system is exceptionally tight in terms of generating low sulfur product, and maybe that’s a post IMO effect. But is that a fair statement? Have you seen kind of a post IMO have you seen a structural change or tightness in the ability of the global refining system to generate ultra-low-sulfur product? And is that something that sticks with us for a long time and on the margin drives higher distillate margins?

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

Ryan Todd: Right. Thanks. And then maybe just one on the renewable diesel side. I mean early guidance for the 2023 to 2025 time frame didn’t appear very supportive for renewable diesel on its surface. Any thoughts on what your takeaways were overall, whether you see the market as potentially oversupplied this year? And whether this may result in pushing more marginal players out of the market? Obviously, you have a structural cost advantage, so you’re on the low end of the curve. But do you expect €“ I guess, how did you read the guidance? What do you think the impact will be over the next year or two on the market?

Jason Fraser: Well, so one thing that we saw with the RFS obligation is that they kept the ethanol target at 15 billion gallons, which means you’re still going to be in a situation at some point in the year where you have to use the D4 RIN to cover the D6 obligation because the ethanol blending won’t reach 15 billion gallons. So that mechanism is still in there. To your point, the future obligations were higher, but not as high as people expected. And when you saw that announcement come out, you did see a big drop in soybean oil prices as well as a lot of pressure on €“ or question on whether or not all these soybean crush facilities were going to get built based on that lower obligation going forward. So it’s a little bit of a mixed bag that, there’s still going to be short on the D6 RIN, but there is definitely a lower growth curve on the D4 RIN in this current proposal.

So we’ll have to see how that plays out. There’s still a lot of talk about a lot of the policy trying to move away from soybean oil as a feedstock, both in Europe and in the US, at least in terms of conversations. And so as everyone’s trying to figure out is that part of what’s at play with this lower RFS proposal. So €“ but overall, as you said, we’re a waste oil units that isn’t affected by that. And as you said, we will be competitive regardless of the obligation compared to our peers. So we’ll have to see how the — we’ll just have to see how this plays out. I don’t know, Rich, you had other comments about the future outlook on the RFS proposal. I know we’re

Rich Walsh: Yeah. I mean, one thing I would hit on is the elements that they put in that’s probably the thing that we find most problematic with the rule. EPA is trying to convert the RFS into a subsidy for EVs, for autos. And, obviously, we’ll be commenting very heavy on that. We feel that the RFS is really set out by Congress and the intent was for it to be used to promote liquid renewable fuels like the use of soybean and corn and for ethanol. And we don’t think trying to convert this into some kind of a user it for EV purposes really is consistent with the underlying obligations and intent of Congress with the RFS.

Ryan Todd: Good. Thank you.

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

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

Gary Simmons: Well, previously, we said we would take a pause after DGD 3 and reassess the market. So we’re — like you said, we’re still lining out DGD 3. Its project went great. It came in under budget. It was nine months ahead of schedule. It’s met design. It’s met its design rates already. And I’ll just say that the project team, the operations team and the fuel compliance team did a great job making this a very smooth start-up, and we’re not having any problem moving sales out of DGD 3 into markets. So as I said before, we haven’t seen an increase in feedstock prices. So everything looks very competitive with DGD3 coming up. That all being said, I think we continue to do the engineering on the SAP project. For the DGD platform, and then we continue to support the Navigator pipeline for the CO2 sequestration for our ethanol plants. So all of that still says that there’s a lot of opportunity with our platform, given its location and competitive position.

Connor Lynagh: What’s your thinking around exploring potential alcohol to jet or other avenues to approach the SAF market.

Rich Walsh: Yeah, I think there’s two things. Obviously, what’s key to that is that the sequestration project has to go first. In order for ethanol to qualify for SAF, you have to get below the 50% GHG targets for the EU. And so if you look — if you assume that pipeline is done in the next couple of years, it will qualify our ethanol platform into SAF. And so the other thing that we’ve learned is with the SAF projects, you still have to blend that with conventional jet to make the final SAF product. So if you think about our platform, we have the ethanol, we have the carbon sequestration and we’ve got the conventional jet on the refining side. It does look like we would have a lot of advantage in just a complete supply chain into a finished SAF product. So that all looks like it’s something we will continue to look at as we get closer to reality on this carbon sequestration pipeline.

Connor Lynagh: All right. Thanks very much.

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

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

Gary Simmons: Yes. So I think in the short-term, a lot of what you’re seeing, the premiums on jet are primarily in New York Harbor in the Florida market. And it’s still a bit of an overhang from the winter storm outages that we had in the US Gulf Coast, causing those markets to be exceptionally tight. It looks to us like probably mid-month in February, you’ll get some resupply, which will help jet supply in those regions. But overall, we expect jet demand to increase significantly this year and overall, a lot of tightness in the distillate markets.

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

Gary Simmons: Yes. So we share the view that the DOE numbers look low to us and we would expect them to be corrected going forward. Our wholesale numbers are trending pretty high. So gasoline volumes through our wholesale channel are about 12% above where they were pre-pandemic levels, which we don’t necessarily think is representative of the broader markets either. For us, I think the number which we focus on are more around the mobility data, which is kind of showing vehicle miles traveled flat to slightly above where it was pre-pandemic levels with some improvements in the efficiency of the fleet, it would say gasoline demand down maybe in the 2% range is what we kind of believe is most likely.

Neil Mehta: That makes more sense. Thanks, guys.

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

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

Lane Riggs: So this is Lane. I’ll start on that. I mean, I think we’ll probably — we always look at heavy crude versus fuel oil. I mean one of the things that’s happened sort of Russia big buyers have been 100 out of Russia. And obviously, we don’t buy that anymore. So we’ve canvased the world and figured out alternative sort of fuel oil feedstocks and they’re plentiful largely based on what Gary has mentioned. I mean, you have a lot of incremental crude going into low complexity and they’re struggling making sulfur. So you can see that in the 3.5 weight percent discount to virtually everything else. And so we do believe that’s going to continue. I think through this year. So, at Valero, you’ll see us buy more heavy crude, we want post coker, and you’ll see us buy some more fuel oil and less intermediates.

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

Jason Gabelman: Got it. Thanks. And my follow-up is on DGD. Given the start-up of DGD 3, I suspect there was a larger distribution to the joint venture partners. So, I was wondering if you’re willing to disclose what that distribution was? And now that you’re going to likely moving forward to have more access to the cash from DGD in the form of ongoing distributions, does that impact how you think about the payout ratio at all? Thanks.

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

Jason Fraser: Yes, that’s right. With having DGD 3 finish, we’ll have excess cash. And they’re always looking at new capital projects and maybe they’ll find another way to deploy it otherwise, there should be cash coming out. And we do include that in our calculus when we’re looking at payout ratios, but I guess that’s all I had on it.

Jason Gabelman: Got it. Thanks.

Operator: Thank you. The next question is coming from William — I’m sorry, Matthew Blair of TPH. Please go ahead.

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

Lane Riggs: Yes, I don’t know that you need to be more conservative on capture rates. Obviously, we have seasonal maintenance. We’d have to look at the material balance and figure out how that actually impacts the sort of the dollars per barrel capture rates. So, I wouldn’t jump to conclusion of changes, but appreciably from Q4 to Q1, both quarters, you’re blending butane both quarters, you have fairly wide sour discounts. So, I don’t — we’ll just have to see how that plays out. But obviously, we have some maintenance occurring, our turnaround were occurring in Q1 and that’s normal for us. That’s — when we do turn around, this is a heavy quarter for us versus the rest of the year.

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

Rich Walsh: Well, I guess, we don’t normally get into that level of detail on feeds. What I would say is the whole DGD platform is big for waste oils. And so it’s always going to favor the and tallows and inedible corn oil over other feeds from a CI standpoint. So how each of those individual feedstocks play is always €“ that’s very dynamic. And the thing I’d say is what we do see, maybe just to add some color, is we are running a lot more of international feedstocks, both coming from Darling as well as just more broadly in the world. So €“ and those are waste oils. We ran some veg oil in the fourth quarter because as we spoke earlier, the prices of it became attractive. But going forward, I think it’s always going to be some mix of those three waste oils as the most attractive feeds.

Matthew Blair: Great. Thank you.

Operator: Thank you. We’re showing no additional questions in queue 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. Obviously, if you have any additional questions, please feel free to reach out to the IR team. Thanks, everyone, and have a great week.

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