Valero Energy Corp (VLO) — Q4 2022 Earnings Call Transcript

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.

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 incentivized 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 the 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 a 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.

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. 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 member 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 spending 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.

Good morning, everyone. Thank you for taking my questions.

Good morning, Theresa.

My first question is 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 diesel as well as the geopolitical situation?

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 residues. 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.

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?

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.

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.

Thank you.

Hi, good morning, everyone. Thanks for taking my questions. Happy New Year, guys for those I haven't spoken to yet.

Thanks, Doug.

Joe, I'm not sure who you want to address this to, but I'm interested in the economics of the coker. When you initially outlined the plan to bring it online, the diesel resid market was quite different from what we see today. Could you share your expectations for the earnings potential of that facility now, compared to when the project was first proposed? I also have a follow-up.

Yes. No, Doug, we'll let Lane take a crack at this one.

Hi, Doug. I hope you're doing well. I just want to remind everyone that our final investment decision was $325 million, which is based on mid-cycle estimates. Looking back to 2018, I believe the EBITDA was around $420 million. In the fourth quarter, it could be around $700 million, possibly a bit more. Using those kinds of margins, I can't say for sure that we have amazing foresight, but we are fortunate, and being good at what we do helps. Assuming everything holds, I think our outlook for this year regarding resid prices and distillate cracks is quite favorable, with timing being very good.

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?

I'm going to be fairly specific right here. We're going to be mechanically complete somewhere late February, early March, and we expect oil in somewhere late April or early May.

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.

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

Yes, I'll provide some context regarding the quarter. We exceeded our goal, which will change our perspective going forward. Before the pandemic, we often achieved returns at the high end or even above our target payout range of 40% to 50%. During the pandemic, we remained dedicated to our dividend, which resulted in us exceeding our target range. As you know, we had to take on an additional $4 billion in debt in 2020 due to COVID. One of our main objectives as financial conditions improved post-COVID was to repay this extra debt, and we've been actively working on that. While pursuing this goal of reducing debt, we committed to staying at the lower end of our payout range, which we've done. In the fourth quarter, we successfully repurchased $442 million of debt, marking the final step in achieving our $4 billion deleveraging goal. Consequently, during the quarter, we increased our stock purchases to $1.8 billion and ended the year with a payout ratio of 45%. This allows us to return to the midpoint of our target range for the full year. Now that we've paid off our pandemic debt and strengthened our cash balance, you can expect us to aim for mid-level or higher payout targets considering the current construction margin environment. Regarding the dividend, we aim for a sustainable and competitive dividend compared to our peers and would like to demonstrate growth. We haven't seen any dividend growth since the first quarter of 2020 due to the pandemic and our focus on rebuilding cash and reducing debt. Having met those goals, we now intend to resume a growth trend moving forward.

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.

Net zero debt, Doug.

Thank you everybody.

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?

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.

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?

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.

Great. I'll – that's my two, so I'll leave it there. Thank you.

Thanks, Roger.

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.

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.

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?

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 “soybean oil”, came pretty flat to waste oils in October and November. But then we saw the “soybean 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.

Thank you.

Good morning. Thank you.

Good morning, Sam.

So in the prepared remarks, you mentioned European energy costs 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?

I'll start and if Gary wants to add, this is Lane. Natural gas in the UK and the Netherlands is still around $20 per million BTU. In comparison, the cost in Houston is probably just above three. There remains a significant disparity in natural gas costs. However, our Pembroke refinery serves as a reference point, and natural gas prices haven't influenced our operations in over a year. Currently, we don't have a steam methane reformer or a large hydrocracker, limiting our insight into how these costs impact the economics of those units. Nevertheless, despite high natural gas prices in Europe, our signals at the Pembroke refinery remain unchanged.

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.

We like where you're going, Sam.

Yes. If it is positively impacting the entire Gulf Coast system due to the optimization opportunities it presents, then understanding the contribution at the plant level would be beneficial.

What was that last question?

Contribution at the plant level?

We appreciate your comments. However, we cannot definitively state that. The coker operates by reducing heaviness in the refinery, and as for our intermediate purchases, we expect a significant reduction based on our VGO comments. This enhances our vertical integration of the refinery, making it much less reliant on intermediates to operate efficiently.

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.

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

You too.

Hey, guys. Good morning.

Good morning.

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 does that impact Port Arthur in terms of the crude layout of throughput and product yield?

Are you referring to the turnaround aspect of it?

No, outside of it. I mean, we understand the turnaround. Now, you have two cokers.

That's what I've alluded to a little bit.

But I'm more interested if it is not doing the turnaround, how the new coker addition will impact in terms of your yield?

As I mentioned to Sam, we will significantly increase our heavy crude processing. Currently, we primarily handle light and medium crudes, but you'll notice a considerable shift towards heavier crudes over time. While I’m assessing past investment decisions, it’s not as substantial as one might expect. Regarding distillate production, that’s the primary output for us, which ranges from an increase of 15% to 25% based on the type of crude used. Essentially, this will lead to a decrease in our feedstock purchases as well as improved turnaround efficiency.

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?

No, we're not increasing by 50,000 barrels per day. We're adjusting our operations. You'll see our rates. I have to be careful about what I share publicly. We currently run anywhere from 340 to 360 and up to 375, depending on the type of crude. I believe we could potentially increase by 30 to 40 on crude, depending on whether we are processing heavier or lighter crude. When we alter our crude input, we need to adjust our intermediate purchases to complete our conversion units. This means we will reduce our intermediate purchases significantly, depending on the type of crude and how we adjust the refinery operations. However, it's not an increase of 150,000 barrels.

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?

Will it increase?

We will need to follow up on that. It's going to be considerable. I need to check the volume adjustments we made. We will get back to you on that. I'm not sure about the specifics at this moment.

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?

Well, I didn't really see much improvement compared to the prior quarter. The way we look at it is…

North Atlantic we see $29.

No, but I'm saying versus prior like I said.

Capture was only up a margin.

Yeah. Capture rate was up just a little bit.

Okay. Thank you.

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 products? And is that something that sticks with us for a long time and on the margin drives higher distillate margins?

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.

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?

One thing we observed with the RFS obligation is that the ethanol target remains at 15 billion gallons. This means there will be times during the year when the D4 RIN will need to be used to satisfy the D6 obligation since ethanol blending won't hit the 15 billion gallon mark. While the future obligations were indeed higher, they weren't as elevated as some anticipated. Following this announcement, soybean oil prices dropped significantly, raising concerns about whether new soybean crush facilities would be constructed given the reduced future obligations. It's a mixed situation; we will still face shortages in D6 RINs, but the growth projection for D4 RINs is definitely lower with the current proposal. We'll need to see how this unfolds. Ongoing discussions regarding policies aiming to reduce reliance on soybean oil as a feedstock are happening in both Europe and the US, which may influence the implications of this lower RFS proposal. However, we operate waste oil units that aren't affected by these changes, and we remain competitive regardless of the obligations compared to our competitors. We'll have to wait to see how this develops. Rich, do you have any additional thoughts on the future outlook regarding the RFS proposal?

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 heavily 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 for EV purposes really is consistent with the underlying obligations and intent of Congress with the RFS.

Good. Thank you.

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 does 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?

Previously, we mentioned we would take a break after DGD 3 to reassess the market. We're still working on DGD 3, which has gone incredibly well. It came in under budget and was completed nine months ahead of schedule. It has met its design specifications and performance rates. I want to acknowledge the project team, the operations team, and the fuel compliance team for ensuring a seamless start-up, and we're effectively coordinating sales from DGD 3 into markets. As I mentioned earlier, we have not experienced an increase in feedstock prices, making DGD 3 look very competitive. We are also proceeding with engineering for the SAP project related to the DGD platform and supporting the Navigator pipeline for CO2 sequestration at our ethanol plants. Overall, there are significant opportunities with our platform due to its advantageous location and competitive stance.

What's your thinking around exploring potential alcohol to jet or other avenues to approach the SAF market?

There are two key factors to consider. First, the sequestration project needs to be completed. For ethanol to qualify for sustainable aviation fuel, it must meet the EU's greenhouse gas targets of less than 50%. Assuming that the pipeline is completed in the next few years, our ethanol platform will be eligible for sustainable aviation fuel. Additionally, we have learned that sustainable aviation fuel must be blended with conventional jet fuel to create the final product. Considering our position, we have ethanol, carbon sequestration capabilities, and conventional jet fuel refining, which gives us a significant advantage in providing a complete supply chain for finished sustainable aviation fuel. We will continue to pursue this as we advance toward the realization of the carbon sequestration pipeline.

All right. Thanks very much.

Yes. Good morning, team, and congratulations on a great quarter. The first question was about jet cracks. We're noticing that the premium compared to diesel is increasing significantly in some markets. I would love to hear your thoughts on whether you believe there is a structural premium for jet fuel and how you foresee these premiums evolving over time.

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.

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?

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.

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.

This is Lane. I'll begin. We continually evaluate heavy crude in relation to fuel oil. One notable change is that we no longer purchase from major Russian buyers. We have researched alternative fuel oil feedstocks globally, which are abundant, as Gary mentioned. There is a significant amount of incremental crude entering low complexity, and they are having difficulty producing sulfur, evident in the significant discount for 3.5 weight percent compared to nearly everything else. We expect this trend to persist, and throughout this year at Valero, we plan to purchase more heavy crude and more fuel oil while reducing our reliance on intermediates.

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.

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.

I'll begin with the DGD aspect, which has just launched. We haven't yet discussed cash distributions, but the expectation for this year is that as capital spending wraps up on the project, there should be an increase in cash flow from the joint venture. Jason, do you want to add anything?

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.

Got it. Thanks.

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 your 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?

I don't think there's a need to be more conservative regarding capture rates. We have seasonal maintenance that we need to evaluate in terms of how it affects the dollar per barrel capture rates. I wouldn't rush to conclusions about changes. From Q4 to Q1, both quarters involve butane blending and have notable sour discounts. We'll need to see how this unfolds. Additionally, we are experiencing some maintenance with our turnaround happening in Q1, which is typical for us. This quarter tends to be heavier compared to the rest of the year.

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?

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.

Great. Thank you.

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.