Valero Energy Q4 2022 Earnings Call Transcript

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Provided by Quartr
January 26, 2023

Key Takeaways

  • 97% refinery capacity utilization in Q4 2022 was the highest since 2018, driving strong margin capture.
  • Q4 2022 adjusted net income reached $8.45 per share versus $2.41 in Q4 2021, with full-year adjusted EPS of $29.16 up from $2.81.
  • The Port Arthur Renewable Diesel Plant started ahead of schedule and under budget, boosting DGD’s annual renewable diesel capacity to 1.2 billion gallons.
  • The Fort Arthur Coker project remains on track for Q2 2023 completion, enhancing sour crude processing and turnaround efficiency.
  • Refining cash operating expenses rose by $0.14 per barrel in Q4 2022, driven by higher natural gas prices.
AI Generated. May Contain Errors.
Earnings Conference Call
Valero Energy Q4 2022
00:00 / 00:00

There are 19 speakers on the call.

Operator

Greetings and welcome to the Valero's 4th 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.

Operator

Thank you, Mr. Mueller. You may begin.

Speaker 1

Good morning, everyone, and welcome to Valero Energy Corporation's 4th 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 1 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 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 Expectations or predictions of the future are forward looking statements intended to be covered by Safe Harbor provisions under federal securities laws.

Speaker 1

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.

Speaker 2

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 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.

Speaker 2

Our refining system also benefited from heavily discounted sour 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 Fort Arthur Coker project is expected to be completed in the Q2 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 4th quarter With the successful commissioning and start up of the new DGD Port Arthur Renewable Diesel Plant in November.

Speaker 2

That project was completed under budget and ahead of schedule and brings DGD's annual production capacity to approximately 1,200,000,000 gallons of renewable diesel and 50,000,000 gallons of renewable naphtha. In the ethanol segment, BlackRock and Navigator's carbon sequestration project is still progressing on schedule and is We expect to be the anchor shipper with 8 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 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 U.

Speaker 2

S. Coastal refiners that have crude oil supply and natural gas advantages relative to global refiners. And we continue to see large discounts for heavy sour crude oils and fuel oils that we can process in our system. The start up of the Port Arthur Coker is also expected to have a significant earnings contribution in the back half of twenty twenty three, 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.

Speaker 2

So with that, Homer, I'll hand the call back to you.

Speaker 1

Thanks, Joe. For the Q4 of 2022, net Income attributable to Valero stockholders was $3,100,000,000 or $8.15 per share Compared to $1,000,000,000 or $2.46 per share for the Q4 of 2021. Q4 2022 adjusted net income attributable to Valero stockholders was $3,200,000,000 or $8.45 per share Compared to $988,000,000 or $2.41 per share for the Q4 of 2021. For 2022, net income attributable to Valero stockholders was $11,500,000,000 or $29.04 per share Compared to $930,000,000 or $2.27 per share in 2021. 20 22 adjusted net income Attributable to Valero stockholders was $11,600,000,000 or $29.16 per share compared to 1,200,000,000 For $2.81 per share in 2021.

Speaker 1

For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial The refining segment reported $4,300,000,000 of operating income for the Q4 of 2022, Compared to $1,300,000,000 for the Q4 of 2021. Adjusted operating income for the 4th Quarter of 2022 was $4,400,000,000 compared to $1,100,000,000 for the Q4 of 2021. Refining throughput volumes in the Q4 of 2022 averaged 3,000,000 barrels per day. Throughput capacity utilization was 97% in the 4th quarter of 2022. Refining cash operating expenses of $5 per barrel in the Q4 of 2022 We're $0.14 per barrel higher than the Q4 of 2021, primarily attributed to higher natural gas prices.

Speaker 1

Renewable diesel segment operating income was $261,000,000 for the Q4 of 2022 compared to $150,000,000 for the Q4 2021. Renewable diesel sales volumes averaged 2,400,000 gallons per day in the Q4 of 2022, Which was 851,000 gallons per day higher than the Q4 of 2021. The higher sales volumes were due to the impact of additional volumes from the DGD The St. Charles plant expansion and the Q4 2022 start up of the DGD Port Arthur plant. The ethanol segment reported $7,000,000 of operating income for the Q4 of 2022 compared to $4,000,000 for the Q4 of 2021.

Speaker 1

Adjusted operating income for the Q4 of 2022 was 69,000,000 compared to 475,000,000 for the Q4 of 2021. Ethanol production volumes averaged 4,100,000 gallons per day in the Q4 of 2022. The higher operating income in the Q4 of 21 was primarily attributed to multiyearhighethanolpricesduetostrongdemandandlowinventories. For the Q4 of 2022, G and A expenses were $282,000,000 and net interest expense was 137,000,000 G and A expenses were $934,000,000 in 2022. Depreciation and amortization expense was 633,000,000 And income tax expense was $1,000,000,000 for the Q4 of 2022.

Speaker 1

The annual effective tax rate was 22% for 2022. Net cash provided by operating activities was $4,100,000,000 in the Q4 of 2022 $12,600,000,000 for the full year. Excluding the unfavorable change in working capital of $9,000,000 in the 4th quarter $1,600,000,000 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 $4,000,000,000 for the 4th quarter and $13,800,000,000 for the full year. Regarding investing activities, we made $640,000,000 of capital investments in the Q4 of 2022, Of which 349,000,000 was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance And $291,000,000 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 $538,000,000 in the Q4 of 2022 And $2,300,000,000 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.

Speaker 1

Moving to financing activities, we returned $2,200,000,000 to our stock Holders in the Q4 of 2022 $6,100,000,000 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 4th quarter that reduced Valero's debt by $442,000,000 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 twenty twenty one have collectively reduced Valero's debt by over $4,000,000,000 We ended the year with $9,200,000,000 of total debt, dollars 2,400,000,000 of finance lease obligations and $4,900,000,000 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-nineteen pandemic. And we ended the year well capitalized with $5,400,000,000 of available liquidity, excluding cash.

Speaker 1

Turning to guidance, we expect capital investments attributable to Valero for 2023 to be approximately £2,000,000,000 which includes expenditures for turnarounds, catalysts and joint venture investments. About £1,500,000,000 of that is allocated to Refining throughput volumes to fall within the following ranges: Gulf Coast at 1.59000000 to 1.64000000 barrels per day Mid Continent at 415,000 to 435,000 barrels per day. West Coast at 200 45,000 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 Q1 to be approximately $4.95 per barrel. With respect to the Renewable Diesel segment, we expect sales volumes to be approximately 1,200,000,000 gallons in 2023.

Speaker 1

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 4,000,000 gallons per day in the Q1. Operating expenses should average $0.51 per gallon, which includes $0.05 per gallon for non cash costs such as depreciation and amortization. For the Q1, net interest expense should be about $130,000,000 and total depreciation and amortization expense should Approximately $655,000,000 For 2023, we expect G and A expenses, Excluding corporate depreciation to be approximately $925,000,000 That concludes our opening remarks. Before we open the call to questions, please adhere to our protocol of limiting each turn in the Q and A to 2 questions.

Operator

Thank you. The floor is now open for questions. A confirmation tone will indicate your line is in the question The first question is coming from Theresa Chen of Barclays. Please go ahead.

Speaker 3

Good morning, everyone. Thank you for taking my questions. My first question is related to morning related to your macro outlook over the near term. 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?

Speaker 4

Teresa, this is Gary. I think initially, we felt like even with the ramp up in sanctions, you would 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 BGO and diesel coming out of Russia when the sanctions take place.

Speaker 3

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?

Speaker 5

Probably half of that.

Speaker 4

Yes. So the market is very, very tight. We're looking at total light product inventories 55,000,000 barrels below the 5 year average. And so typically this is a period of time where you The restocking take place and with the winter storm outage and high maintenance activity, we just haven't been able to restock inventories, which

Speaker 5

And Therese, this is Lane. So as we've been pretty consistent, we don't do a whole lot of commentary around our turnaround But nonetheless, I mean, the Q1 and the 3rd quarters are a heavy turnaround period when we have turnarounds. And so, that's sort of Seasonally, that's how we execute our maintenance.

Speaker 3

Thank you.

Operator

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

Speaker 6

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

Speaker 2

Thanks, Doug.

Speaker 6

Joe, I don't know who you want to direct this to, 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 Market than we are today. So could you as you see the earnings power of that facility as it stands maybe at 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.

Speaker 2

Doug, we'll let Lane take a crack at this one.

Speaker 5

Hey, Doug. I hope you're doing all right. It's so really just to remind everybody, our FID, I think, was 3 $25,000,000 that's sort of based on mid cycle. We sort of look back at it in sort of 2018, I think the EBITDA is around 4.20. If you use sort of 4th quarter, it's on the order of probably $700,000,000 maybe a little bit more dollars.

Speaker 5

So if you use those kind of margins, so obviously, It's I don't know if we had the incredible foresight, but it's great to be lucky. Lucky than good. Exactly right. So yes, you'll have a Assuming all this holds and I think we are sorry, at least for our outlook, at least for this year is that these sort of resid prices and distillate cracks will hold, it will be The timing is pretty perfect.

Speaker 6

Just to be clearly, 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?

Speaker 5

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

Speaker 6

Thank you. 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?

Speaker 6

Thanks.

Speaker 2

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

Speaker 7

Yes. I'll Give a little context too, because this quarter we did meet a goal which will kind of change how we look at things. So back prior to the pandemic, we were frequent 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 away above our 40% to 50% target range. And as you know, during COVID, we had to take on another $4,000,000,000 of debt in 2020.

Speaker 7

So one of our main objectives as the financial situations improve post COVID was to pay back 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 Q4, we were able to repurchase $442,000,000 of debt, which is the final step in us meeting our goal of deleveraging by $4,000,000,000 So with that insight, during the quarter, we increased our stock purchases to $1,800,000,000 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 built 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.

Speaker 7

Yes, you'd asked about dividend too, which is other piece of the puzzle. So we continue to aim for dividend at 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 Q1 of 2020. Because first of all, we had the pandemic, which we had to work our way through.

Speaker 7

And then we're rebuilding cash And working our debt down. So now, as I've said, we've got to met those goals, so we would like to return to a pattern of growth as we move forward.

Speaker 6

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

Speaker 2

Net 0 debt, Doug.

Speaker 8

Thank you.

Operator

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

Speaker 9

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 SBR releases a 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 And sanctions coming up, that's really more of a product thing.

Speaker 9

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 diffs as we get into the early days of 'twenty three here?

Speaker 4

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.

Speaker 4

And so all those factors come into play, Affecting 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.

Speaker 9

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 At Ignatius in general, what is your expectation for a substitute feedstock into the summer, the secondary units and the Kind of follow on impacts on distillate production.

Speaker 5

Hey, Roger. This is Lane. I'll take a shot at it. I think what you'll see, we were concerned about it going into this past BGO availability that we sort of squeaked through with some of the way some of the refineries in the Middle East started up. And I think, Pete, some people stockpile BGO.

Speaker 5

I mean, the answer to that is it will remain tight. And ultimately, what it affects is gasoline production. If If you believe distillate cracks are going to hang in there where they are, you'll have clear margins by BPO into a hydrocracker, but it will challenge FCC's economics through the summer, it's in fact as it gets tight.

Speaker 9

Great. I'll that's my 2, so I'll leave it there. Thank you.

Speaker 2

Thanks, Roger.

Operator

Thank you. The next question is coming

Speaker 10

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 quotas. So anything on China reopening would be helpful. Thanks.

Speaker 4

Yes. 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 It's 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.

Speaker 4

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 production.

Speaker 10

Great. Thank you. That's helpful. And then on the renewable diesel side, can you talk about how the feedstock market is absorbing DGD3 and assuming this is the case why it's been kind of easier than having pushed up Advantage feedstock the way it did with DGD2?

Speaker 11

Yes, this is Eric. We haven't really seen a big change in feedstock costs with DGD3 coming on. As you said, we did see a big change where waste oil feeds really equilibrated to soybean oil with DGD2 in But with the start up of DGD3, we've seen prices hold pretty flat. We saw that Soybean oil actually, at least Seabaugh's soybean oil quote came pretty flat to waste oils in October November, but then we saw The soybean oil quote dropped really with the EPA announcement on their RFS obligations for the next 3 years. And so But overall, to answer your question, we haven't seen a big change in feedstock prices.

Speaker 11

It's been pretty stable.

Speaker 8

Thank you.

Operator

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

Speaker 12

Good morning. Thank

Speaker 2

you. Good morning, sir.

Speaker 12

So in the prepared remarks, you mentioned European energy costs driving Optimization opportunities in the U. S. 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?

Speaker 5

I'll start and if Gary wants to sort of add, this is Lane, by the way, Sam. So natural gas still at the U. K. And really in the Netherlands is still normally around $20 per 1,000,000 BTU. And comparing that today, sort of the Houston I mean, Henry Hub is probably at normally 3 and change.

Speaker 5

So there's still a significant difference 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 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, hasn't limited, hasn't changed our signals, which is run MAX at our Pembroke Refinery.

Speaker 12

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 It's 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 a facility that's probably the most valuable fuels complex in the world at this point, I And I don't even know what the question is, to be honest with you, but I'm just trying to get at the high level contribution to But

Speaker 2

we like where you're going, Sam. Yes.

Speaker 12

I mean, if it has it, 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.

Speaker 5

What was that last closing? Contribution at

Speaker 1

the plant level.

Speaker 5

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 we'll heavy the refinery up and our intermediate purchases So if you think about our VGO comments, we'll be down significantly. So it better integrates sort of vertically integrates that refinery and makes it way less sort of, as 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.

Speaker 2

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.

Speaker 12

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

Speaker 5

You too.

Operator

Thank you. The next question is coming from Paul Cheng of Scotiabank, please go ahead.

Speaker 13

Hey, guys. Good morning. Can I go back into part of, I mean, with the coke coming on stream, we understand that, I mean, one of the Decision behind is that it will allow you during the turnaround, you can still want the facility? But during the long turnaround period, How does Yintech port offer in terms of the cruise slate overall throughput and product yield?

Speaker 5

So are you talking about the turnaround portion of it?

Speaker 8

Or are you just

Speaker 14

talking about

Speaker 13

No, outside the turnaround. I mean, we understand the Yes, it is not during the turnaround. How the new coker edition will really impact in terms of your So

Speaker 5

as I said on Sam, it's we'll heavy up considerably. At the end of the day, we run some light crudes and medium crudes. You'll see us run significantly more It may be plus rate probably over time by 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 diet in terms of distillate. What it really is, is a reduction in In addition to like we said, it's a turnaround efficiency.

Speaker 13

Right. So we assume that is a 55,000 barrel today, So you will see an incremental one of happy and mediums to the tune of about 150,000 barrels per day?

Speaker 5

I'm sorry, Paul, can you repeat that?

Speaker 13

No. The coke, the capacity is 55,000 barrels per day. So we assume you're heavier up by about 150,000 barrels per day of the heavy and mediums out crew?

Speaker 5

No, we're not increasing to about 150,000 barrels a day. We're heading up. You'll see our rates I don't normally go from I don't know, it's public here. I got to be careful. I'm okay with the stance to cause here.

Speaker 5

It's sort of We run anywhere from 3.40 to 3.60 today, 3.75 depending on the crude diet. 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. We do this all the time.

Speaker 5

Whenever we change our crude diet, we're sort of have to spot in intermediate purchases to finish our conversion units out. What will happen is we'll reduce the amount of intermediate purchases depending by significantly on the base and tuning the refinery between how heavy we are and how We'll change sort of how our crude run rates. So but it's not a plus 1.

Speaker 13

No, no, no. I'm saying not the overall throughput increase by 1.50%. I'm saying that will you increase the run of a And medium sour crude by 150,000 barrels per day with this quarter.

Speaker 12

We

Speaker 5

would have to get back to you. It's going to be a lot. I mean, I'd have to go back and see how much heavy we incremented on terms of the volume. So and we'll have to get back with you. You can get back with Homer Assuming we disclose that, I

Speaker 15

don't know what

Speaker 5

are we going

Speaker 13

to do. And second question is that In your law of 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 condition, if that's any?

Speaker 5

So Paul, which margin or Valero's overall

Speaker 13

North Atlantic. You're both and Nancy.

Speaker 5

Well, I didn't really it's not that much stronger versus the prior quarter. I mean,

Speaker 1

it's right.

Speaker 5

Just the way we look at it North Atlantic. Yes. It went from

Speaker 13

North Atlantic, you did, I think, dollars 29.

Speaker 5

No, but I'm saying versus prior.

Speaker 1

It's capture was only up on March.

Speaker 5

Yes, capture rate was up just a little bit.

Operator

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

Speaker 8

Thanks. Maybe a follow-up on some things that you maybe touched on a little bit earlier in the call. If I think from a macro Some of the what appear to be at least whether they're structural or lingering Improvements in 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?

Speaker 8

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?

Speaker 4

Yes, I think so. So you can see that a couple of places you can really see it, 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

Speaker 8

Great. Thanks. And then maybe just one on the renewable diesel side. I mean, RVO guidance for the 2023 to 2025 timeframe 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.

Speaker 8

Obviously, you have a structural cost advantage, so you're on the low end of

Speaker 14

the curve.

Speaker 8

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 2 on the market?

Speaker 11

Well, so one thing that we saw with the RFS obligation is that they kept the ethanol target at 15,000,000,000 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 15,000,000,000 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 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 A short on the D6 RIN, but there is definitely a lower growth curve on the D4 RIN in this current proposal.

Speaker 11

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 U. S, at least in terms of conversations. And so 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 oils unit that isn't affected by that.

Speaker 11

And as you said, we will be competitive regardless of the obligation Compared to our peers. So we'll have to see how we'll just have to see how this plays out. I don't know, Rich, if you had other comments about sort of the future outlook on The RFS proposal, I know we're there's going to be lots of dollars in the history.

Speaker 16

Yes. I mean, the one thing I would hit on is this the elements of the ERIN that they put in it. That's probably The thing that we find most problematic with the rule, EPA is trying to convert the RFS to a subsidy for EVs, 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 usurpate for EV purposes really is

Speaker 10

Okay. Thank you.

Operator

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

Speaker 17

Yes, thanks. I kind of wanted 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 this sort of policy Vision make you think about DGD4 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?

Speaker 11

Well, previously we said we would take a pause after DGD 3 and kind of reassess the market. So we're and like you said, we're still lining out DGD 3. It's Project went great. It came in under budget. It was 9 months ahead of schedule.

Speaker 11

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 DGD3 into markets. So As I said before, we haven't seen an increase in feedstock prices. So everything looks very competitive with PGD3 coming up. That all being said, I think we continue to do the engineering on the SAF project for the DGD platform and then we continue To support the Navigator pipeline for the CO2 sequestration for our ethanol plants.

Speaker 11

So all of that still says that there's a lot of opportunity With our platform, given its location and competitive position.

Speaker 17

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

Speaker 11

Yes, I think there's 2 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 these SAF projects, you still have to blend that with Conventional jet to make the final SAF product.

Speaker 11

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 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.

Speaker 17

All right. Thanks very much.

Operator

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

Speaker 18

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 some markets. I'd love your perspective on, you think there's a structural premium in jet And how do you see those premiums playing out over time?

Speaker 4

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 and the Florida market, and it's still a bit of an overhang from the winter storm outages that we had in the U. S. 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.

Speaker 18

That's helpful. That's a follow-up is around just the demand levels. I mean, we've historically anchored to EIA on some of the U. S. Demand levels and The numbers are noisy.

Speaker 18

I mean, I think the last 4 week trailing number was down 11%, which is hard to reconcile with the fact that DST is 20% below the 5 year from an inventory perspective and gasoline below the 5 year as well. So just would love to hear what you're seeing through your own wholesale system in And any thoughts on real time color there?

Speaker 4

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.

Speaker 4

It would say gasoline demand down maybe in the 2% range is what we kind of believe is most likely.

Speaker 18

Yes, that makes more sense. Thanks guys.

Operator

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

Speaker 15

Good morning. I got a couple of questions. First, I want to ask about the U. S. Gulf Coast Intermediate imports, the resids.

Speaker 15

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 still. And as these RISID 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 to the Discount to statewide 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?

Speaker 15

And I have a follow-up. Thanks.

Speaker 5

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 post Russia, we used to be big buyers of M100 out of Russia and obviously, we don't buy that anymore. So we've Canvas the world and figure 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.

Speaker 5

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 post coker and you'll see us buy some more fuel oil and less intermediates.

Speaker 4

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, third quarter, It was rebalancing the trade flows, but in the Q4, we certainly saw a significant impact.

Speaker 15

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 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?

Speaker 15

Thanks.

Speaker 11

I'll start on just on the DGD side, it just started up. We haven't even got to the conversation of 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. Now Jason, if you have comments

Speaker 16

on that.

Speaker 7

Yes, that's right, Eric. With having DGD3 finished, we'll have excess cash and I know 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.

Speaker 15

Got it. Thanks.

Operator

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

Speaker 14

Hey, thanks for taking my question. Good morning, everyone. Do

Speaker 13

You have

Speaker 14

any early thoughts on the Q1 'twenty three 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 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?

Speaker 5

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 balances to figure out how that actually Impacts the sort of the dollars per barrel capture rates. I wouldn't jump to conclusion and change this appreciably from Q4 to Q1.

Speaker 5

Both quarters you're Blending butane both quarters, you have fairly white sour discount. So I don't we'll just have to see how that plays out. But obviously, We have some maintenance and occurring or turnarounds are occurring in Q1 and that's normal for us. When we do turnarounds, this is a heavy quarter for us versus the rest of the year.

Speaker 14

Got it. And then For DGD, how should we think about the feedstock mix going forward? Your old guidance was 1 third fats, 1 third Corn oil, 1 third EUCO, but you started up DGD3 and your partners acquired some more tallow Production. So it seems like we might want to inch up maybe a little bit on the FAS compared to that 1 third guidance, maybe inch Down on the UCO, is that fair and do you have anything more specific on that?

Speaker 11

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 built for waste oils. And so it's always going to favor the Yukos and tallos and Inedible corn oil over other feeds from a CI standpoint. So how each of those Individual feedstocks play as always, that's very dynamic. And then the thing I'd say is what we do see, maybe just to add some colors, we are running a lot more of International feedstocks, both coming from Darling as well as just more broadly in the world.

Speaker 11

So And those are waste oils. We ran some veg oil in the Q4, because as we spoke earlier, the Prices of it became attractive, but going forward, it's I think it's always going to be some mix of those 3 waste oils as the most attractive feeds.

Speaker 14

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.

Speaker 1

Thanks, Donna. Appreciate everyone joining us today. Obviously, if you have any additional 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

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