Valero Energy Corporation

Greetings and welcome to Valero Energy Corporation's first quarter 2021 earnings conference call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host. Homer Bular, Vice President, Investor Relations.

Good morning, everyone, and welcome to Valero Energy Corporation's first quarter 2021 earnings conference call. With me today are Joel Gorder, our Chairman and CEO, Lane Riggs, our President and COO, Jason Frazier, 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. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now I'll turn the call over to Jill for opening remarks.

Thanks, Homer, and good morning, everyone. The refining business saw a strong recovery in the first quarter as various pandemic-imposed restrictions were eased or withdrawn and as more and more people received vaccinations. However, Winter storm Yuri disrupted many U.S. Gulf Coast and mid-continent facilities in February due to the freeze and utilities curtailments. Although our refineries and plants in those regions were also impacted, they did not suffer any significant mechanical damage and were restarted within a short period after the storm. While we did incur extremely high energy costs, I'm very proud of the Valero team for safely managing the crisis by idling or shutting down the affected facilities and resuming operations without incident. With many of the country's Gulf Coast and mid-continent refineries offline due to the storm, there was a significant 60 million barrel drawdown of surplus product inventories in the U.S., bringing product inventories to normal levels. Lower product inventories, coupled with increasing product demand, improved refining margins significantly from the prior quarter. Crude oil discounts were also wider for Canadian Heavy and WTI in the first quarter relative to the fourth quarter of last year, providing additional support to refining margins. In addition, our renewable diesel segment continues to provide solid earnings and set records for operating income and renewable diesel product margin in the first quarter of 2021. Our wholesale operations also continue to see positive trends in US demand, And we expanded our supply into Mexico with current sales of over 60,000 barrels per day, which should continue to increase with the ramp up of supply through the Vera Cruz terminal. On the strategic front, we continue to evaluate and pursue economic projects that lower the carbon intensity of all of our products. In March, we announced that we were partnering with BlackRock and Navigator to develop a carbon capture system in the Midwest. allowing for connectivity of eight of our ethanol plants to the system. In addition to the tax credit benefit for CO2 capture and storage, Valero will also capture higher value for the lower carbon intensity ethanol product in low carbon fuel standard markets such as California. The system is expected to be capable of storing 5 million metric tons of CO2 per year. Our Diamond Green Diesel II project at St. Charles remains on budget and is now expected to be operational in the middle of the fourth quarter of this year. The expansion is expected to increase renewable diesel production capacity by 400 million gallons per year, bringing the total capacity at St. Charles to 690 million gallons per year. The expansion will also allow us to market 30 million gallons per year of renewable naphtha from DGD1 and DGD2 into low-carbon fuel markets. The Renewable Diesel Project at Port Arthur, or DGD3, continues to move forward as well and is expected to be operational in the second half of 2023. With the completion of this 470 million gallons per year capacity plant, DGD's combined annual capacity is expected to be 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. With respect to our refinery optimization projects, we remain on track to complete the Pembroke Cogen project in the third quarter of this year, and the Port Arthur Coker project is expected to be completed in 2023. As we head into summer, we believe that there's a pent-up desire among much of the population to travel and take vacations, which should drive incremental demand for transportation fuels. We're already seeing a strong recovery in gasoline and diesel demand at 93% and 100% of pre-pandemic levels, respectively. Since March, air travel has also increased. as reflected in TSA data, which shows that passenger count is now nearly double of what it was in January. We're also seeing positive signs in the crude market, with wider discounts for sour crude oils and residual feedstocks relative to Brent as incremental crude oil from the Middle East comes to market. All these positive data points, coupled with less refining capacity as a result of refinery rationalizations, should lead to continued improvement in refining margins in the coming months. We've already seen the impacts of these improving market indicators, with Folero having positive operating income and operating cash flow in March. In closing, we're encouraged by the outlook on refining as product demand steadily improves towards pre-pandemic levels, which should continue to have a positive impact on refining margins. We believe these improvements, coupled with our growth strategy and low-carbon renewable fuels, will further strengthen our long-term competitive advantage. So with that, Homer, I'll hand the call back to you.

Thanks, Joe. For the first quarter of 2021, we incurred a net loss attributable to Valero stockholders of $704 million, or $1.73 per share. compared to a net loss of $1.9 billion or $4.54 per share for the first quarter of 2020. The first quarter 2021 operating loss includes estimated excess energy costs of $579 million or $1.15 per share. For the first quarter of 2020, adjusted net income attributable to Valero stockholders was $140 million or $0.34 per share. The adjusted results exclude an after-tax lower of cost or market or LCM inventory valuation adjustment of approximately $2 billion. For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany the earnings release. The refining segment reported an operating loss of $592 million in the first quarter of 2021. compared to an operating loss of $2.1 billion in the first quarter of 2020. For the first quarter of 2021, adjusted operating loss for the refining segment was $554 million, compared to adjusted operating income of $329 million for the first quarter of 2020, which excludes the LCM inventory valuation adjustments. The refining segment operating loss for the first quarter of 2021 includes estimated excess energy costs of $525 million related to impacts from winter storm URI. Refining throughput volumes in the first quarter of 2021 averaged 2.4 million barrels per day, which was 414,000 barrels per day lower than the first quarter of 2020 due to scheduled maintenance and disruptions resulting from winter storm URI. Throughput capacity utilization was 77% in the first quarter of 2021. Refining cash operating expenses of $6.78 per barrel were higher than guidance of $4.75 per barrel, primarily due to estimated excess energy costs related to impacts from winter storm URI of $2.21 per barrel. Operating income for the renewable diesel segment was a record $203 million in the first quarter of 2021 compared to $198 million for the first quarter of 2020. Renewable diesel sales volumes averaged 867,000 gallons per day in the first quarter of 2021. The ethanol segment reported an operating loss of $56 million for the first quarter of 2021 compared to an operating loss of $197 million for the first quarter of 2020. The operating loss for the first quarter of 2021 includes estimated excess energy costs of $54 million related to impacts from winter storm URIE. The first quarter of 2020 adjusted operating loss, which excludes the LCM inventory valuation adjustment, was 69 million. Ethanol production volumes averaged 3.6 million gallons per day in the first quarter of 2021, which was 541,000 gallons per day, lower than the first quarter of 2020. For the first quarter of 2021, G&A expenses were 208 million and net interest expense was 149 million. Depreciation and amortization expense was $578 million, and the income tax benefit was $148 million for the first quarter of 2021. The effective tax rate was 19%. Debt cash used in operating activities was $52 million in the first quarter of 2021, excluding the favorable impact from the change in working capital of $184 million and our joint venture partners' 50% share of Diamond Green Diesel's net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash used in operating activities was $344 million. With regard to investing activities, we made $582 million of total capital investments in the first quarter of 2021, of which $333 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $249 million was for growing the business. Excluding capital investments attributable to our partner's 50% share of Diamond Green Diesel and those related to other variable interest entities, capital investments attributable to Bolero were $479 million in the first quarter of 2021. On April 19, we sold a partial membership interest in the Pasadena Marine Terminal joint venture for $270 million. Moving to financing activities, we returned $400 million to our stockholders in the first quarter of 2021 through our dividend. And as you saw earlier this week, our Board of Directors approved a regular quarterly dividend of $0.98 per share. With respect to our balance sheet at quarter end, total debt and finance lease obligations were $14.7 billion, and cash and cash equivalents were $2.3 billion. The debt-to-capitalization ratio net of cash and cash equivalents was 40%. At the end of March, we had $5.9 billion of available liquidity excluding cash. Turning to guidance, we expect capital investments attributable to Valero for 2021 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments. About 60% of our capital investments is allocated to sustaining the business and 40% to growth. Over half of our growth capex in 2021 is allocated to expanding our renewable diesel business. For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.65 to 1.7 million barrels per day. Mid-continent at 430 to 450,000 barrels per day. West Coast at 250 to 270,000 barrels per day. And North Atlantic at 340 to 360,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $4.20 per barrel. With respect to the renewable diesel segment, with the startup of DGD2 in the fourth quarter, we now expect sales volumes to average 1 million gallons per day in 2021. Operating expenses in 2021 should be $0.50 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.1 million gallons per day in the second quarter. Operating expenses should average $0.38 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the second quarter, net interest expense should be about $150 million, and total depreciation and amortization expense should be approximately $590 million. For 2021, we still expect GNA expenses, excluding corporate depreciation, to be approximately $850 million, and the annual effective tax rate should approximate the U.S. statutory rate. Lastly, as we reported last quarter, we expect to receive a cash tax refund of approximately $1 billion later this year. That concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers 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.

At this time, we'll be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. Our first question today is from Roger Reed of Wells Fargo. Please proceed with your question.

Thank you. Good morning.

Good morning, Roger.

I guess I'd like to take into account your outlook, well, comments about where we are in terms of demand and your outlook in terms of volumes for Q2, and then look at the crude runs that you've had, Q1 of 21 versus Q1 of 20. It seems like all the decline came out of light, sweet crudes and kind of residuals and other. And I was curious, as we go forward, your comment about a little more crude coming from OPEC, Should we anticipate more of the volumes likely to be on the medium and heavy side, you know, the sour side where you tend to get a little more advantage on crude differentials? Or, you know, is it really that the opportunity lies on the light sweet crude side just because that's what's come off in terms of the system?

How many questions was that, Rod?

Well, I know it's a two-question rule, but I'm just – it's a way of trying to – No, no, we got it, we got it. Which crude are you going to run?

No, I'm kidding you. Gary's prepared for this, so let him fire away.

Hey, good morning, Roger. You know, our view coming into the years, and we would see fairly narrow crude quality differentials for the first half of the year, But as global oil demand picked up, you know, a great percentage of that would be filled with additional OPEC production, which would cause the quality differentials to widen back out. I think, you know, by and large, that view is still holding. Most forecasts show about 4 million barrels a day of additional OPEC production coming on the market the second half of the year. In fact, at the last OPEC meeting, they're saying, you know, we could see as much as 2.1 million barrels of that as early as July. You know, I think the only thing that's different is the quality differentials have widened a little bit faster than what we thought, and it's for a number of reasons. The winter storm brought down a lot of high-complexity refining capacity that pushed medium and heavy sour crude back to the market and helped widen those quality differentials. After the winter storm, we had the release from the Strategic Petroleum Reserve, put 10 million barrels of medium sour on the market, which, again, pressured that ASCII differential down. We're seeing more Iranian and Venezuelan barrels on the market. Of course, not flowing to the U.S., but flowing to the Far East, and it's taken some of the pressure off the medium sours in the U.S. Gulf Coast. And then recently we had the refinery fire in Mexico, you know, which has put more Maya out on the market. So, you know, we think the combination of the events that happened recently, additional OPEC barrels on the market. We also think you'll see more heavy Canadian with the recovery in flat price and production quotas being lifted there. that the differentials will continue to widen. To your question, we have seen a switch in economic signals. Of course, it's very dependent on location and refinery configuration, but some of our refineries today, the economic signals are pointing us to run more heavy sour, and we're seeing fairly equal economics between medium sour grades and light sweet.

All right, guys, I'll leave it there since I did ask the question.

Thank you. We always appreciate it. Thanks.

The next question is from Theresa Chen. Please proceed with your question.

Good morning, everyone. I'd like to dig a little deeper on your comments about your carbon capture strategy. Maybe beginning with how your partnership with Navigator came about and, you know, what can we expect in terms of the economics net to Valero? And if you intend to do something similar for your other facilities in the Gulf Coast, for example, especially on the heels of a competitor announcement, building this type of infrastructure out in a major way along the Houston ship channel?

No, that's a good question. And Rich and Martin worked together, and Rich was kind of the architect behind this. So we'll let him take a crack at this.

Sure. So I'll just kind of back up. So Valero is going to be the anchor shipper on this project. BlackRock is the financial backer. And Navigator is leading the engineering, construction, and operations for the carbon capture and sequestration. we're estimating that, you know, by doing this, we'll lower the carbon intensity of the ethanol that we produce from a kind of a 70 CI down to a 40 CI. And I'll let Martin kind of talk about the value creation there. But today the CI, uh, ethanol carries a premium into the California market and the economics are supported by the, the California market and the 45, uh, Q tax credit. And, uh, We expect that further markets will develop for the low-carbon fuels, so increasing demand for this premium product. Today, navigators out there, they've launched their non-binding open season, which is basically to kind of determine what kind of demand will be for this project so that they can right-size the project and also kind of optimize on the routing The open season is going very well, and we're seeing strong interest from ethanol producers and other industry players. But we're especially surprised by the strong interest from the fertilizer plants. And given this strong interest in the project, they will be moving forward with a binding open season this summer. And if you wanted more information, they've got a website out there. It's just navigatorco2.com, which kind of goes over the – kind of the open season process and kind of a preliminary mapping of how the pipeline system is going to kind of work.

Thanks, Rich. Hey, Teresa, this is Martin. Yeah, so the 70 to 40 CI reduction in ethanol, that's worth like right now 47 cents a gallon at $200 a ton. And even out into the future, it stays right in that range, about 50 cents a gallon at a $200 per ton carbon price. As Rich said, you know, we've got California and Oregon with programs now. We expect New York, New Mexico, Washington, they all have legislation in place for low carbon. You know, we expect those to happen over some time in the next few years. So as this project's got, you know, a timeline to completion, we expect, you know, no slowing down in low carbon mandates or clean fuel standard mandates. So that's the additional thing. demand for the product there.

Very helpful. Thank you. And then within the, you know, broader LCSS framework, I wanted to ask about your renewable diesel business given the strength in margins as well as volumes. And, you know, maybe just on the impressive margin per unit results, can you explain what drove that this quarter, especially with the backdrop of rising feedstock costs and if these high margins are sustainable?

Sure, I'll take a stab at that. Well, it was a good quarter, right, 275 per gallon EBITDA. And if you look versus first quarter of 20, soybean oil price is up 1.6 times, but the D4 RIN price is up 2.6 times. So the D4 RIN has done a lot of lifting, and that's provided margin. We're looking, you know, I think if you look over history, we've had a pretty good stress test the last three years. We've had a wide variation in RIN prices, wide variation in feedstock prices, wide variation in ULSD prices, yet our margin has only varied from 217 a gallon EBITDA in 2018 to 237 a gallon EBITDA in 2020, and now, you know, Last first quarter of 20, first quarter of 21, about the same in this 270 EBITDA range. So, again, a pretty good stress test, so we feel pretty comfortable about those kind of margins going forward for the foreseeable future.

Thank you.

The next question is from Phil Gresh of J.P. Morgan. Please proceed with your question.

Yes. Hi. Good morning. Morning, Phil. My first question is on the second quarter utilization guidance. The midpoint there was about 87% with 91%, I think, in the Gulf Coast and the MidCon. And obviously that's a bit above the April DOEs, and there's obviously seasonality benefits as we move into the summer. So I'm just curious how you expect demand and utilization to progress into the summer. And, you know, do you think the crack spreads today – weren't running that high of a level of utilization, or is it an expectation of even higher cracks moving forward? Thank you.

Hey, Phil, this is Lane. So really, if you look at our guidance, it's somewhat consistent with where we're kind of running today. But there is, you know, we have turnarounds in some of the refineries. But the current cracks, there's a call on refining. to run at a reasonably high rate. It's just a matter of how you're going to posture yourself and look at your supply chain. So we're sort of inching up as an industry, but certainly where margins are today and our margins going forward, you'll see increasing utilization in the industry. Okay, got it.

And the second question would be on the balance sheet. Obviously you have the tax refund coming. There is the Pasadena asset sale here in April. So I'm curious how you think about the leverage targets and whether there might be other asset sale opportunities like Pasadena, just some low-hanging fruit out there that could help accelerate any debt reduction objectives. Thank you.

Thanks. Yeah, this is Jason. I can talk a little bit about how we're seeing the next 12 months with regard to debt reduction and capital allocation. Then, Joe, if you want somebody else to talk about other potential opportunities. Yeah. Okay. Well, like Joe said, you know, in March we had our first month with positive operating income and cash flow, and the demand in the markets are looking good. So things are definitely improving. It's hard to tell the exact pace that the margins and cash flows are going to recover, but we're certainly headed in the right direction. So some of the things we'll be looking at as margins start normalizing and cash flows start normalizing is the first thing we want to do is build our cash balance. we'll likely take our target up from the $2 billion range to the $3 billion plus range. That'll help our net at the cap come down naturally as we do that. And as you asked about on the leverage side, the additional debt we took on was relatively short term. The vast majority was three to five years in the base case. But we are going to look to pull some of that back in early. And the first thing we'll look at is this $575 million of three-year floaters. that are callable beginning in September. So I imagine that's the first thing we'll take up.

And then, Phil, just as it relates to the asset sales, we don't have anything else in mind. And frankly, we didn't do this because we were in any kind of desperate need for cash. We did it because it was a smart thing to do financially. And when we developed this project and a few others that we developed and then kind of baseloaded, the plan was that we would want use of the asset but not necessarily need to own the asset. And so this was part of the plan all along. It's not something that I would consider to be abnormal, but at the same time, the motivation for it was that it was an attractive business transaction rather than a need for cash.

Okay, great. Can I just clarify, is the billion-dollar tax refund still a 2Q – target, or just latest thoughts on magnitude and timing? Thank you.

Yeah, well, that is what we were thinking before. You know, to talk a little bit more about that, we filed our tax, both our return and our refund request back in mid-January, which was a really big accomplishment for our tax department. We've never filed that early before, and I think most people don't. But unfortunately, it looks like the IRS is experiencing significant delays in processing these returns and the refund requests. My understanding was that they'd normally turn around in a 90 to 120-day timeframe, but with these COVID impacts, the timing's uncertain this year. We certainly still expect to receive the full tax refund, but it may slip, you know, from the second quarter. Thank you very much.

The next question is from Prashant Rao of Citigroup. Please proceed with your question.

Hi, good morning. Thanks for taking the question. I have a two-parter, and I'll leave it with my compound question here. On DGD, on the feedstock side, you know, Martin, I think you're being a bit humble in saying the RIN was doing a lot of lifting. I mean, it was, but you guys also have advantage feedstock in the way you've set up that project. So I'm curious about your outlook going forward. One, you know, It looks like, I know soybean is not something you're that exposed to, but the curve is showing some backwardation ahead, but really not a full mean reversion. So curious about, you know, what gets us going in terms of some deflation, reversing some of these inflation trends we've seen over the last couple of quarters for the overall complex. I guess soy being kind of the key that people key off of when they're making their assumptions. And then second, as we see that happen, again, You know, how should we think about divergences or the advantage in your feedstocks like DCO or animal fats, Yuko, other feedstocks that you're using, the non-soy versus SBO as we start to see things deflate? I'll leave it with that one. Thank you.

Sure, Prashant. So I think what you have to do is if you kind of step back and look, what's really, you know, soybean oil gets the attention in the United States, but what's really going on is the worldwide veg oil price, and it's up. And why it's up, first of all, it was really low in 2018 and 2019, so we had periods where it was low versus history, and by that I mean relative to ULSD. So soybean oil pricing is driven by the global supply and demand of veg oils. Soybean oil, palm oil, and rapeseed oil are all up 60% to 95% year on year. Palm oil production in Indonesia was off because of a drought in 2020 and labor shortages due to COVID-19. You also had U.S. soybean oil production in the 1920 crop year or just soybean production was like 80% of the previous year. So you also have to remember you had the trade sanctions, so China wasn't in. China pulled down stocks a lot. They weren't in the market for the soybean oil, so prices dropped. Not as much was produced. Well, now China's back in the market. The world's recovering, so you've got a big demand now out there for veg oils. So we kind of got into this place because of low prices and we'll get out of it because of high prices. So all these can be grown on demand. So, you know, the cure for high prices is high prices. So, you know, we'll eventually work our way out of this. It's going to take a little while. Now, obviously, DGD's advantage is we're not, you know, we're not running the veg oils other than the distiller's corn oil, which is, you know, an inedible veg oil. So we expect to continue to see those feedstocks priced at a discount to soybean oil. But the biggest advantage is the CI score of those oils, those waste oils compared to a veg oil or compared to the soybean oil in most jurisdictions. So that's really what drives DGD. And, you know, by having our robust pretreatment system, our location, our ability to run anything is just a huge advantage.

Thanks for that. That's super helpful. I'll leave it at that.

The next question is from Doug Leggett of Bank of America. Please proceed with your question.

Doug, you might be on mute, buddy.

Is that any better, guys? Can you hear me?

You bet. Good morning, Doug.

Okay. Good stuff. Good morning, Joe. Joe, I want to ask also about the broader carbon footprint of Valero. I'm looking at slide five on your deck, and I'm just wondering with the latest announcement for the carbon pipeline and with obviously the potential for additional DGD plants, what is the objective for Valero overall? Is it basically to get that carbon footprint neutral negative? What's the general strategic objective of how you're building up your green credentials, if you like?

That's a good question, Doug. And obviously, I mean, you can tell from the chart and you can tell from where we're spending our capital that we have a clear recognition here that low carbon fuels are going to be in much greater demand going forward. The interesting thing here from our perspective is that we've been able to come up with low-carbon fuel projects and projects that have enabled us to reduce the carbon intensity of some of our other fuels with projects that have significant returns also. I mean, it's one thing to try to have that drive to find compliance with Paris, to go to carbon neutrality and so on. That's all fine and good. But it's also critical that when we're on that path that we do it in a way that continues to deliver financial returns for our investors. And so we continue to look at not only the projects that are listed here. I mean, obviously, the carbon sequestration pipeline is the next extension after we were in ethanol first and then renewable diesel, now this. And there's other projects that we're taking a look at, too, that are going to help us on this path going forward. The targets we've set for ourselves to hit by 2025 we think are very achievable, and I don't think that you should expect that our goals are going to continue to be pushed forward from there. So we want to be viable for the long term. We believe that liquid fuels are going to be part of the energy mix going forward. It's infeasible to think that they wouldn't, and we just want to do our part and continue to provide low-carbon products.

I appreciate the full answer. I do have a quick follow-up, and it's related specifically to LCFS. And I guess I'm going to be very honest with you, Joel. We were having a tough time, you know, modelling the sustainable discounted free cash flow, if you like, for Diamond Green Diesel, because we don't know what the LCFS, how that's going to evolve. So I just wonder if you could, you know, whichever one of you guys wants to answer this. How do you think about when you look at the economics of the project, how do you guys think about forecasting the scenarios for how LCFS can evolve? Because obviously everybody and their dog now is kind of coming up with projects, including electric vehicle charging stations, which are another offset, which can start to bite into that LCFS. So how are you thinking about modeling the payback and the assumption of LCFS in your projects? I'll leave it there. Thanks. Okay.

Yeah, this is Martin. I mean, the way we're looking at it is obviously California's there with the program. We think if Oregon's there with the program, Canada's got a clean fuel standard that's going to be in place, and the Canadian demand on diesel is about twice as high as California demand. And then you've got all these other programs. You've got the EU now with Red 2 out to 2030, California out to 2030. So while there's a lot of projects announced, there's also a lot of incremental demand announced. And if you look at generation to date, you know, what's carrying the load for California is renewable diesel, biodiesel, and ethanol. It's 70% of the credits generated is that. So when we look at the timeline for the economics and what we're looking at for the Diamond Green projects, you know, they pay out pretty quick, right? So, but we're not, and we don't see anything changing materially and certainly through 2025 type timeframe and even beyond that, you know, we don't see this changing that much. So we feel pretty good about that. I think CARB, if you have a carbon price go down, they're going to adjust that up. I mean, I think they've pretty well signaled that this $200 a ton is kind of the, the sweet spot for them and 200, 200 plus. And so we feel pretty good about demand. And I think the flip side is a lot of these projects that are announced, if you go back in history, they just don't happen. And we don't see anything that's going to change that trend.

Doug, you may recall when we issued guidance on the DGD2, right? Like our portion of the cost was 550 million. And our EBITDA guidance was 250, and that was based on $1.26 EBITDA, right? And you compare that to the 275 that we generated last quarter. It just gives you some context of, you know, how much room there is.

Very, very quick payback. Guys, maybe just tag on one last one real quick. Valero's view on Calgary tax, positive or negative, and I'll leave it there. Thanks.

Who wants to take that one?

Rich, carbon tax. So you see various discussion points out there. You've got some trade groups. You've got other folks talking about carbon tax. Generally speaking, in terms of best ways to reduce carbon emissions, the most efficient way to do that in the economy is with a tax. We would say the key components of this is the tax has to be applied correctly. broadly across the entire economy. You need to make sure it doesn't result in, you know, exporting the emissions outside the country. So you're going to have to have some kind of border adjustment process around it. But yeah, you know, I think a carbon tax is an efficient way to address some of these issues and to help lower carbon. I'd point out that we do quite well in the, you know, in this low carbon fuel environment. And so, you know, we think we would be advantaged under that regime as well.

Thanks very much, fellas.

The next question is from Sam Margolin of Wolf Research. Please proceed with your question. Good morning. How's everybody doing?

Hi, Sam. Well, and you?

Good, thanks. Thank you, sir. I have a question to start off about RINs, and I guess it affects both DGD and the refining business. You know, we're starting to see some companies emerge that are RINs-generating companies, Businesses that are selling forward their RINs, in some cases not even to obligated parties at a fixed price, and then the off-taker takes the risk of the RIN price. Is that something that's interesting to you either at DGD to kind of smooth out variability in results or even in the refining segment to add some visibility there?

Hi, Sam. This is Lane. You know, we obviously are in that position of buying REN. So any way that we could, you know, any counterparty that has a novel way to get RENs on the market, we obviously could be on the other side of that. As to it's related to renewable diesel, I'm going to kick it over to Martin.

Yeah, Sam. So I think, you know, when we look at our margin structure, there's probably no need. I mean, we think, you know, what the REN, if you step back and look at this, the price of the D4 REN is, is based on the spread between biodiesel and ULSD. And then the driver for the biodiesel price is almost entirely soybean oil because that's the marginal feed for the biodiesel producer. So then, therefore, if you have at a given ULSD price, the D4 RIN is high if soybean oil is high and the D4 RIN is low if soybean oil is low. So as renewable diesel – feedstock prices move with soybean oil, renewable diesel margin is not necessarily higher with D4 RENs, as they appreciate. Now, D6 RENs are a whole different story. You know, they're dependent on the renewable volume obligation and whether D4 RENs are needed to satisfy the total renewable fuels obligation. If D4 RENs are needed, then that D6 price is going to approach the D4 price, and that's the case we're in today. The D4 is right up against the D6. So D4s are tied to the production cost of biodiesel. We don't see that fundamentally changing. And then the D6 just depends on the total renewable fuel obligation and whether additional biodiesels needed to balance that equation. So a D6 can be about anywhere, a ceiling of D4 down to, but a D4 has got some fundamentals behind it, so we don't really see the need to protect that.

Okay. Thank you. And this follow-up is about carbon capture, and it sort of relates to Doug's last question on a carbon tax. But, you know, just because of your experience in the LCFS and now as a shipper in a CCS project, Valera's is very far ahead of the industry in terms of understanding you know, the impact of a price of carbon or cost of carbon on energy markets and, you know, how it flows to the consumer. And there's a debate now about, you know, whether that is a restriction on the potential scale of carbon capture as a solution. So I'd ask you just to kind of comment broadly or specifically about how you see the world with the carbon price and, you know, whether it's even applicable to, say, outfit an entire refining system with some kind of carbon capture solution, if that makes sense based on the way it interacts with consumers. Thank you.

Yeah, there's a lot of facets to that question. I mean, you know, I wouldn't presume to say that we're ahead of anybody in looking at this. Perhaps we are, but that's not a claim I don't think that we would be willing to make. Lane can speak here about, you know, potential things that we could look at in the refineries to continue to do this. But, you know, the projects that we've looked at thus far are all related to our core business. There's no particular step out that we've had here. We're in the ethanol business. We've been in the pipeline business for a long time, and we're in the refining business. So you want to speak at all about –

You know, I'm not sure I'd provide a lot of, you know, any tremendous insight into this. I would say that, you know, we went around and looked at all of our sort of our stacks where carbon dioxide obviously is coming out, and we focused our efforts on where carbon dioxide is concentrated in those stacks, and therefore it's easier to sequester it and get it targeted. And when we're doing that in whatever the regime is, whether it's an LCFS market or it's, in the CCUS market. So those are, that's how we're doing it for now, right? And it's again, so you can see where we're, where we've landed. We're doing ethanol. We're looking at, we have some SMRs that predominantly have CO2 as a, as a flue gas, in our flue gas. So those are things that we're analyzing. But there just ultimately needs to be more certainty and more of a larger framework out there for that kind of investment for refining. And, but it, you know, You need a carbon price that's a little bit higher, something more on the order of like the LCFS carbon prices.

Yeah. Anything you want to add, Martin?

No, that's the point. I mean, Lane hit it on the head. When you look at an ethanol plant, you know, it's a cost-effective way. You've got basically pure CO2, and it's at one point, you know, one stack in the plant. Then you also have, you know, this 45Q and the CI reduction. So when you get to a – and then – Steam methane reformer can make sense, too. But when you get to most of our refineries, you know, we're not accessing those low-carbon markets. You've got a lot of sources. So you're going to have to get a higher carbon price, and that's what it's going to take to get more going on in the carbon sequestration market.

Thanks so much. The next question is from Manav Gupta of Credit Suisse. Please proceed with your question.

Hey guys, thank you. Jo, my question is more specific to the U.S. demand. I think we're getting a lot of negative attention from the COVID spikes in other parts of the world, but things are looking pretty good in the U.S. as per your initial comments. I'm trying to understand, in your opinion, how far are we in terms of timeframe where we could go back to pre-pandemic level demand for gasoline, diesel, And domestic jet, even if we leave out the international jet, how far are we from a point where we could see a full recovery in the three key products in the U.S.?

Mr. Simmons.

Yeah, so as Joe mentioned, you know, gasoline recovery has gone very well. A combination of the vaccine rollout and economic stimulus has kind of driven rapid recovery in demand for our products. Our wholesale numbers are pretty consistent with the DOE data. I think our seven-day average is about 95% of pre-pandemic level, which is where Wednesday's stats came out on the DOE as well. So, you know, a little bit below the five-year average, but well within the five-year average range. You know, we're pretty bullish on gasoline going forward, not only due to the pace of recovery, but we think there's a number of factors that could be very supportive for gasoline demand. As people return to a normal style of life, we're seeing that people are driving more and kind of avoiding mass transit for the summer season. We believe that, you know, a lot of people that will want to go on vacation will, again, maybe avoid travel on an airplane and take more driving vacations. And then just as Jill alluded to, because people have felt trapped in their home for a year now, they'll spend more of the discretionary income on experiences like vacation rather than things. So, you know, everything domestically on the gasoline front looks very good. And even though we've seen spikes of COVID cases around the world, our domestic export markets are starting to pick up as well. You know, Mexico, gasoline demand in March was up 11% from February. So the gasoline side looks very good. On the diesel side, you know, we've really been in this mode where diesel demand is almost fully recovered. We're starting to see very strong diesel demand, especially in our mid-continent system today as agricultural demand is starting to kick in. And, you know, the combination of the economic stimulus and infrastructure build we think drives economic growth and will cause sustained strong diesel demand moving forward. You also talked about jet. And certainly, you know, we felt like jet would lag in terms of demand recovery. And it has. But, you know, if you look at the DOE stats this week, we were at 76% pre-pandemic levels. And I think if you look at a lot of the leading indicators, you know, the TSA passenger counts look very strong, and that's not fully showing up in the DOE data yet. You know, so far the airlines have chosen just to put more passengers on a plane, but we're getting to an inflection point where now they're starting to add flights. You can see that in jet fuel nominations and also the fact that airlines are calling their pilots and their crews back, you know, and starting to add flights. So I think, you know, If you look at where jet demand could go pre-pandemic, you know, about 81% of flights in the U.S. were domestic flights. I think we could get that demand back. That last 20%, you know, in terms of international travel, probably take a little longer to recover there.

Perfect. My quick follow-up here is your renewable diesel results clearly are reflecting the two very high-quality companies working together, and it's kind of showing up in the results. And my point is, I think if something is still working so well, then you should do more of it. As I understand, when you designed DJD3, you did leave space at Port Arthur for a DJD4, exactly like DJD1 and 2 at St. Charles. So at what point will you wait for DJD2 to start up, but At what point does Valero and Darling come together and start looking at a DJD4 at Port Arthur facility? And I'll leave it there.

Thanks, Mark.

So who wants to do that, Mark or Lane? I'll take a shot at it. So, you know, everything you said is absolutely correct. We've left, you know, we've left plot area to look at a diamond green for there. But we want to see how the market develops. We want to understand sustainable aviation fuel, which is another option for us in this space. We're developing projects along both those lines, and we'll just see how the world works. But we've got to get two of these started up and get them done. As you've seen, our schedules are doing much better, and so we're actually bringing these to market earlier. And our real focus right now is to do just that. Our guides go there regularly. We're very much involved in trying to accelerate these projects and bring them forward in any way possible because, as you can see, the economics and the projects.

Thank you so much.

The next question is from Paul Chang of Scotiabank. Please proceed with your question.

Hey, guys. Good morning. I think that I'm going to ask two questions. One, yes. Maybe it's a multiple part related to the... Have at it, buddy. We expect nothing less. I'm guilty at charge. For the DGD2, can you give us a percentage of your feedstock that is the advantageous feedstock, like the waste oil and all that? And also that when we're looking at your renewable on the CST supply contract, I think you generate quite a fair amount of the wind there. And can you tell us that, I mean, how much is the wind you generate from those contracts and when that will expire? And when you talk about, I think, Martin, on the CCS benefit in the ethanol, so that we need to egg up your plan out of the 16. So should we assume that half of your full put volume, we get that benefit of the 47 cents per gallon of the credit if we assume the LCFFs are maintained at 200. So that's the first question. Should I wait before I ask the second?

Well, we're trying to figure that one out. I think you're going to have to wait for even the second part of the first question. Paul, on the feedstock, DGD2, I mean, we're expecting... you know, we're going to have a higher mix of, of tallow, but we still expect the feedstocks for DGD2 to, to be advantaged. So it's, you know, it's the same, same cast of characters that, that use cooking oil, the tallow, the, uh, distillers, corn oil off ethanol plants, uh, So that's what we expect heat stock for DGD2 to be. But certainly we'll be heading for more tallow. Used cooking oil is pretty close to being tapped out right now in the U.S. More of that will show up with these high prices. That's what we expect. And then the ethanol question is, what was that? Carbon sequestration, how much of our volume? But we're planning, you know, what we're looking at, certainly the You know, there's been a few questions. The California market can't absorb it all. And, you know, it depends on how many of these ethanol projects happen. California is 10% of the U.S. gasoline market, so it's 10% of the U.S. ethanol market. But we certainly expect, you know, by the time we have these sequestration projects to be in place, something's going to happen in the Northeast. New York's a big market. As we said, New Mexico's got a standard that they're looking at. Depending on what Canada does with the clean fuel standard, that may be an option to go there. We have to see what those final regs look like on carbon sequestration. But again, we just feel like there's going to be more of these clean fuel standards, low carbon fuel standards in the future than there are now. So we'll see how that plays out.

How about the CST supply contract on the wind generation and when that contract expires?

I don't think we can comment on that, unfortunately, Paul.

Okay. The second question is on Mexico. Given the recent political situation looks like AMLO may want to re-nationalize or that we emphasize the state maybe the dominance in some of the sector, including energy. I mean, what is your read for the people on the ground? And is that something that will impact your expansion or that your business over there?

This is Rich Walsh. Let me take an effort at answering that. I mean, I think, you know, when we look at Mexico, you know, first off, they would take a constitutional reform for them to really, you know, formally close out the energy sector. and nationalize it. So, you know, we don't see the political climate supporting that. If you're talking about the recent legislative reforms that Mexico's working on, those are really aimed around, you know, fuel theft and other things. If you're If you've got a legitimate business and you're operating there, as we have, I think we would be able to operate around those regulations. It is a tough regulatory environment to be there, but we're very adept at this stuff. We've moved quickly. We have our market assets on the ground there, and we're working cooperatively with the Mexican government. We think we have a pretty good relationship with them and a good relationship with Mexico. with PIMEX. And so, you know, our view is that, you know, we'll be in Mexico for the long haul, and we think that it's good for the Mexican people, and we think we can help supply and solve some of their energy needs.

Thank you.

The next question is from Paul Sankey of Sankey Research. Please proceed with your question.

Hi, good morning, everyone. The bad news is that my question Yeah, the bad news is I've got eight questions. The good news is you've answered six of them. We've missed you, Paul. I love you, too. One concern of clients has been imports of products into the U.S., and I guess that goes further to refining shutdowns. So could you just talk a little bit about the dynamics of, I guess, Atlantic Basin product markets? I'm just wondering whether that's a sort of dumping of gasoline that's going on and whether these – what you think about refineries getting shut down, because we know you guys are in the right part of the cost curve. I just wondered what your perspective is on whether or not we can rationalize, you know, some of the stuff that's kind of damaging the market, particularly into New York Harbor. And that will be it from me. Thanks, guys. Thanks, Paul.

Yeah, Paul, so I think, you know, in Joe's opening comments, he mentioned we drew down 60 million barrels of light product inventory as a result of the winter storm. It put inventories very, very low in the U.S., and the low inventories really incentivized imports, especially into the East Coast. And so we've seen that, you know, record levels of imports, but you're already starting to see those ARBs close, and the volumes of product flowing from Northwest Europe into New York are slow. In addition to the slowing of imports, we're starting to see exports pick back up. So certainly for us, you know, we had exports down in the first quarter as we replenished inventories, but already in April, you know, our exports are starting to normalize as well. So I do think that was a short-term dynamic that will reverse as we move forward.

Eddie, anything to add on refining shutdowns, you know, the outlook?

You know, I would just say we've had a strategic outlook that says the EU, the southern refineries in Europe will continue to be under pressure, largely driven by just changes in trade flows and then You kind of add to that the ES&G goals of the companies that are there. They're going to continue to be under pressure. And then we also believe and continue to have a sort of an outlook that, you know, Latin American refineries are going to struggle to run at competitive utilization rates. And so that's just going to be an ongoing thing. So to the extent that, you know, that's how the Atlantic Basin tries to sort of settle up in a sort of a post-COVID universe, we'll just see how it all works. Thank you, guys.

The next question is from Ryan Todd of Simmons Energy. Please proceed with your question.

Great. Thanks. Maybe a couple, hopefully fairly quick. One on RNG. I mean, a number of your integrated peers have been involved in partnerships on the RNG side. Is this something you've looked at or do you view it as not relevant? not fitting or competitive within your portfolio compared to the carbon capture and renewable diesel projects. And then maybe a second one, you've got the Pembroke co-gen unit and the diamond pipeline expansion coming on in the second half of this year. There's an EBITDA range associated with those, which is, you know, reasonably wide. Any thoughts on, in the current market, what the potential EBITDA contribution would be and what the big drivers are there in the range?

This is Rich Lashway. I'll take the first piece of the R&G. So we are looking at different opportunities where, you know, we can take the R&G on a kind of a booking claim basis into the refineries to generate the development fuels which fit into into the UK. So that's kind of our foray into it right now, but we still continue to look at other opportunities for RNG into, you know, kind of our supply chain to lower the carbon intensity of the products that we're producing. So we are doing it, but we just, you know, kind of on a quieter kind of scale.

As for the Pembroke Cogen, you know, we expect to start it up here at the, you know, the end of the second quarter, start of the third quarter. I think our FID EBITDA was, like, I want to say 38 million U.S. Obviously, you have some currency risk in that, but, I mean, that's sort of the range on terms of what the EBITDA contribution is on an annual basis. I have a pipeline. We don't have anything to add.

Yeah, that was just an optimization, and the return on that, Ryan, is going to be similar to, like, any logistics project.

Great. Thanks, Thomas.

The next question is from Jason Gabelman of Cowen. Please proceed with your question.

Yeah, hey. Morning, everyone. I wanted to ask on the refinery utilization guidance, specifically in the U.S., excluding North Atlantic, are you essentially running kind of at maximum levels at this point, excluding maintenance, or are you still operating in this framework where you're trying to control or manage the supply chain. That's the first one. And the second one, just on some of the credit prices that impact renewable diesel. First, just the outlook on RENs. Do you expect prices to come off when RBOs are announced or when the small refinery exemption case is concluded? And then conversely, on LCFS prices, They've weakened recently a bit. Just wondering your views on why that is and if you expect them to strengthen.

Thanks. This is Lane. I'll speak to the first question about the outlook. It's somewhat commensurate with where we are today. The call on refining capacity is a fairly decent one. I wouldn't say we're running at max rates, but we're running above. We're running in utilization rates that were more indicative of pre-COVID levels, but they're not we're not completely running at max because we are still being very careful with our supply chain.

Yeah, and then if you talk about the RINs, the RVO will impact the D6 RINs. I talked about that earlier. Once you need to satisfy the total renewable obligation, the D4 RIN is really all about the vegetable prices in the world. So as long as they stay escalated and it's going to take at least a crop cycle to fix that, we expect the D4 bins to stay high. On LCFS, it's off, as you stated. I think a lot of that has to do with the lockdown in California. In my opinion on it, you've just generated less deficits out there. You know, you would think that the credit bank is going to grow marginally in this environment, but as soon as California gets back to speed here, we would expect LCFS prices to rebound, and that should be happening, you know, in the second, third quarters of this year, we would think.

Our next question is from Matthew Blair of Tudor Pickering Holt & Co. Please proceed with your question.

Hey, thanks for squeezing me in here. Lane, you mentioned SAF. How much SAF can DGD produce today? And if that number is low, what's the timing and cost to add in some SAF flexibility? And can you just talk in general about the economics on SAF versus RD and how you see this SAF market developing? Thanks.

Yeah, so I'll start with the very last question you had first. Sustainable aviation fuel requires something above renewable diesel because there's yield penalties and there's capital costs or energy costs all of the above to try to make it. So if you sort of say, hey, I have the investment to make renewable diesel, therefore I need something additional to make sustainable aviation fuel. Today we... We're not configured to make it directly. There's ways that we could make it at a big yield penalty loss. And again, that's back to the cost structure. In terms of the way we think the most economic way to produce it would require a pretty relatively expensive investment. It's essentially adding a reactor into the process and fractionation. You know, there's some costs there, and those are the things that those are the projects we're trying to develop. But you certainly need to, you know, just you do need some, you know, there's people interested in small amounts here and there, and you could probably get to that with fractionation. But to do this in any meaningful way, you're going to need something to get, you know, over the hump here of requiring, you know, jet fuel to be renewable.

Great. Thank you.

There are no additional questions at this time. I would like to turn the call back to Homer Bular for closing remarks.

Great. Well, thank you, everyone, for joining us today. And obviously, if you have any follow-ups, feel free to contact the IR team. Stay safe and healthy, and have a great day. Thanks, everyone.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.