Valero Energy Corp
NYSE:VLO
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Valero Energy Corp
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Greetings, and welcome to the Valero Energy Corporation's First Quarter 2021 Earnings Conference Call. At this time all participants are in a listen-only mode. [Operator instructions]
I would now like to turn the conference over to your host, Homer Bhullar, Vice President Investor Relations.
Good morning, everyone, and welcome to Valero Energy Corporation's first quarter 2021 earnings conference call.
With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and Chief Commercial Officer; and several other members of Valero's senior management team.
If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments.
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 Joe 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The refining business saw a strong recovery in the first quarter as various pandemic imposed restrictions were eased or withdrawn and as more and more people receive vaccinations. However, Winter Storm Uri 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 effected facilities and resuming operations without incident. With many of the countries 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, improve 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 U.S. 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 Veracruz 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 conductivity 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 and low carbon fuel standard markets, such as California. The system is expected to be capable of storing 5 million metric tonnes of CO2 per year. In our Diamond Green Diesel 2 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 DGD 1 and DGD 2 into low carbon fuel markets. The renewable diesel project at Port Arthur or DGD 3 continues to move forward as well. This 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 star 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 bread is an 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 Valero 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 of 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 earning 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. The first quarter 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 adjustment. 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. Refinery throughput volumes in the first quarter of 2021 averaged 2.4 million barrels per day, which was 414 thousand 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 $201 million in the first quarter of 2021 compared to $198 million for the fourth 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 Uri. 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 in the first quarter of 2020. The effective tax rate was 19%.
Net 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 $5820 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 Valero were $479 million in the first quarter of 2021. On April 2019, 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. Almost 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 million to 1.7 million barrels per day, Mid-Continent at 430,000 to 450,000 barrels per day, West Coast at 250,000 to 270,000 barrels per day and North Atlantic at 340,000 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 start up of DGD 2 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 first 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 G&A 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.
[Operator Instructions] Our first question today is from Roger Read 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, your outlook, in terms of volumes for Q2. And then look at the crude runs that you had Q1 of 2021 versus Q1 of 2020. 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, the sour side where you tend to get a little more advantage on crude differentials or 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, Roger?
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.
Crude is supposed to – which crude you're going to run.
No. I'm kidding. Gary is prepared for this, so I'll let him fire away.
Hey, good morning, Roger. 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, a great percentage of that would be filled with additional OPEC production, which would cause the quality differentials to widen back out. I think by and large that that view is still holding. Most forecast show about 4 million barrels a day of additional OPEC production coming on the market to second half of the year. In fact at the last OPEC meeting, they're saying we could see as much as 2.1 million barrels of that as early as July.
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 help 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 ASCI differential.
We're seeing more Iranian and Venezuelan barrels on the market where it's not flowing to the U.S. but flowing through 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, which has put more my out on the market. So we think the combination of the events have happened recently additional OPEC barrels on the market. We also think you'll see more heavy Canadian with the recovery and 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, grapes and Light Sweet.
All right, guys, I'll leave it there since I did ask. Thank you.
No, Roger.
Thank you.
We really appreciated. Thanks.
The next question is from Theresa Chen [Barclays]. Please proceed with your question.
Good morning, everyone. So I'd like to dig a little – morning. 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 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 by doing this, we'll lower the carbon intensity of the ethanol that we produce from kind of a 70 CI down to 40 CI. And I'll let Martin kind of talk about the value creation there. But, today, the CI ethanol carries a premium into the California market, and the economics are supported by the California market and the 45Q tax credit. And we expect that further markets will develop for the low-carbon fuels, so increasing demand for this premium product.
Today, Navigator is out there. They've launched their nonbinding open season, which is basically to kind of determine what kind of demand will be for this project so that they can rightsize 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 the strong interest in the project, they will be moving forward with the 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. Theresa, this is Martin. Yes. So the 70 to a 40 CI reduction in ethanol, that's worth like right now $0.47 a gallon at $200 a ton. And even out into the future, it stays right in that range, about $0.50 a gallon at a $200 per ton carbon price. As Rich said, 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. We expect those to happen over some time in the next few years. So as this project has got a time line to completion, we expect no slowing down in low-carbon mandates or clean fuel standard mandates. So that's the additional demand for the product there.
Very helpful. And then within the broader LCFS framework, I wanted to ask about your renewable diesel business given the strength in margins as well as volumes. And maybe just on the impressive margin per unit result, can you explain what drove that this quarter, especially with the backdrop of rising feedstock cost, and if these high margins are sustainable?
Sure. I'll take a stab at that. Well, it was a good quarter, right? $2.75 per gallon EBITDA and if you look versus first quarter of 2020, 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. So we're looking – 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 ULSD prices, yet our margin has only varied from 2.17 a gallon EBITDA in 2018 to 2.37 a gallon EBITDA in 2020. And now, last – first quarter of 2020, first quarter of 2021, about the same and is 2.70 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.
Good 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 Mid-Con. And obviously, that's a bit above the April DOE, 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 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 – we have turnarounds in some of the refineries. But the current track, there's a call on refining to run at reasonably high rates. It's just a matter of how you're going to posture yourself and look at your supply chain. And so we're sort of inching up as an industry, but certainly, where margins are today and our margins going forward are that 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're thinking 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.
Yes. This is Jason. I can talk a little bit about how we're – see in 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?
Yes. Okay.
Well, like Joe said, in March, we had our first month with positive operating income and cash flow and to 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 flow starting normalizing is 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 will help our net debt to 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 freezer floaters that are callable beginning in September. So I imagine that's the first thing we'll pay up.
And then, Phil, just as it relates to the asset sales, and 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 base loaded, 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 $1 billion tax refund still a 2Q target or just latest thoughts on magnitude and timing? Thank you.
Yes. Well, that is what we were thinking before, to talk a little bit more about that. We filed our tax – both our return and our refund request back in mid-January. It 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 request. My understanding was that they normally turn around in a 90- to 120-day time frame. But with these COVID impacts, timing is uncertain this year. We certainly still expect to receive the full tax refund, but it may slip 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.
Good morning, Prashant.
I wanted to just – I have a two-parter, and I'll leave it with my compound question here, on DGD on the feedstock side. Martin, I think you're being a bit humble in saying the RIN was doing a lot of it – it was, but you guys also are – have advantaged feedstock and the way you set up that project. So I'm curious about your outlook going forward. One, it looks like – I know soybean is not something you were that exposed to, but the curve is showing some backwardation ahead, but really not a full mean reversion. So curious about 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 soybean kind of the key that people key off of when they're making their assumptions?
And then second, as we see that happen, how should we think about divergences or the advantage in your feedstocks like DCO or animal fats, UCO, other feedstocks that you're using the non-soy versus SPO as we start to see things deflate? And I'll leave it with that one.
Sure, Prashant. So I think what you have to do is if you kind of step back and look what's really – soybean oil gets the attention in United States. But what's really going on is the worldwide veg oil price and it's just – it's up. And why it's up? First of all, it was really low in 2018 and 2019. So we had some periods where it was low versus history. And by that, I mean, relative to ULSD. So soybean oil price 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 2019/2020 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 is back in the market. The world is 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 the cure for high prices is high prices. So we'll eventually work our way out of it, but it's going to take a little while. Now obviously, DGD's advantages were we're not running the veg oils other than the distiller’s corn oil, which is an inedible veg oil. So we expect to continue to see those feedstocks price 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 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 Leggate 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 kind of carbon footprint of Valero. I'm looking at Slide 5 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?
Now, 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 its 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 while 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 and 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, Joe. We were having a tough time modeling 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 – 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 in their [indiscernible] 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? And I'll leave it there. Thanks.
Okay. Yes. This is Martin. I mean, the way we're looking at it is – obviously, California is there with the program. We think if Oregon is there with the program. Canada has 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, what's carrying the load for California is renewable diesel, biodiesel and ethanol that 70% of the credits generated is that. So when we look at the time line for the economics and what we're looking at for the Diamond Green projects, they pay out pretty quick, right?
So, but we're not – and we don't see anything changing materially, and certainly through 2025 type time frame and even beyond that, we don't see this is 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 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 – Doug, you may recall when we issued guidance on the DGD 2, right? Like our portion of the cost was $550 million, and our EBITDA guidance was $250 million and that was based on $1.26 EBITDA, right? And you compare that to the $2.75 that we generated last quarter, just gives you some context of how much room there is.
Very, very quick payback. Guys, maybe just tag on one last one real quick. Valero's view on carbon tax, positive or negative? And I'll leave it at that.
Who wants to take that one? Rich?
Carbon tax. Well, so you see various discussion points out there, you've got some trade groups; you've got other folks talking about carbon tax. It will be, 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 broadly across the entire economy. You need to make sure it doesn't result in exporting the emissions outside the country. So you're going to have to have some kind of border adjustment process around it. But, yes, 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 – in this low-carbon fuel environment, and so we think we would be advantaged under that regime as well.
Thanks very much, guys.
The next question is from Sam Margolin of Wolfe Research. Please proceed with your question.
Good morning. How's everybody doing?
All right. 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. We're starting to see some companies emerge that are RINs-generating 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 that variability in results or even in the refining segment to add some visibility there?
Sam, this is Lane. We obviously are in a net position of buying RIN. So any way that we – any counterparty that as a novel way to getting RINs on the market, we obviously could be on the other side of that. As it's related to renewable diesel, I'm going to kick it over Martin.
Yes, Sam. So I think when we look at our margin structure, there's probably no need. I mean we think that – with the RIN, if you step back and look at this, the price of the D4 RIN 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 of soybean oil is low. So as renewable diesel feedstock prices move with soybean oil, renewable diesel margin is not necessarily higher with D4 RINs as they appreciate. Now D6 RINs are a whole different story. They're dependent on the renewable volume obligation and whether D4 RINs are needed to satisfy the total renewable fuels obligation.
If D4 RINs 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 biodiesel is needed to balance that equation. So a D6 can be about anywhere, a ceiling of D4 down to zero, 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. It sort of relates to Doug's last question on a carbon tax. But just because of your experience in the LCFS and now as a shipper in a CCS project, Valero is very far ahead of the industry in terms of understanding the impact of a price of carbon or cost of carbon on energy markets and how it flows to the consumer, and there's a debate now about 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 a carbon price and whether it's 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.
Yes. There's a lot of facets to that question. I mean, 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 potential things that we could look at in the refineries to continue to do this. But the projects that we've looked at thus far 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…
I'm not sure I provide a lot of tremendous insight in this. I would say that we went around and looked at all of our sort of our stacks for carbon dioxide, obviously, is coming on. 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. So those are – and 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 again, so you can see where we've landed. We're doing ethanol. We're looking at – we have some SMRs that predominantly have CO2 as a flue gas and our flue gas. So those sort of things that we're analyzing. But there is ultimately needs to be more certainty and more of a larger framework out there for that kind of investment for refining and – and you need a carbon price that's a little bit higher, something more on the order of like the LCFS carbon prices.
Yes. 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, it's a cost-effective way. You've got basically pure CO2. And it's at one point, one stack in the plant. Then you also have 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, 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. Joe, 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 time frame where we could go back to pre-pandemic level demand for gasoline, diesel and domestic jet, even if you 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?
Yes. So as Joe mentioned, gasoline recovery has gone very well. A combination of the vaccine rollout and economic stimulus has driven a rapid recovery and 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 stats came out on the DOE as well.
So a little bit below the five-year average, but well within the five-year average range. 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 a lot of people that want to go on vacation will again maybe avoid travel on an airplane and taking more driving vacations. And then just as Joe alluded to, because people 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 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.
Mexico gasoline demand in March was up 11% from February. So the gasoline side looks very good. On the diesel side, 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 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 we felt like jet would lag in terms of demand recovery. And it has.
But if you look at the DOE stats this week, we're at 76% pre-pandemic levels. And I think if you look at a lot of the leading indicators, the TSA passenger counts look very strong, and that's not fully showing up in the DOE data yet. 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 and starting to add flights.
So I think if you look at where jet demand could go; pre pandemic, about 81% of flights in the U.S. were domestic flights. I think we could get that demand back. That last 20% in terms of international travel will probably take a little longer to recover there.
Yes. Perfect. My quick follow-up here is your renewable diesel results clearly are reflecting 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 DGD 3, you did leave space at Port Arthur for a DGD 4, exactly like DGD 1 and 2 at St. Charles. So at what point – will you wait for DGD 2 to start up? But at what point does Valero and Darling come together and start looking at a DGD 4 at Port Arthur facility? And I'll leave it there.
Thanks, Manav. So who wants to do that? Martin or Lane?
I'll take a shot. Manav, this is Lane. So everything you said is absolutely correct. We've left – we've left plot area to look at 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 the space. So we're developing projects along both those lines, and we'll just see how the world works. But we 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 guys go there. We're very much involved in trying to accelerate these projects and bring them forward any way possible because of, as you can see, the economics and the projects.
Thank you so much.
The next question is from Paul Cheng of Scotiabank. Please proceed with your question.
Hey, guys. Good morning.
Paul.
I think that I'm going to ask two questions. One is maybe as a multiple part related to the COVID.
Come at it, buddy. Come at it. We expect nothing less.
Joe, I'm guilty as charged. For the DGD 2, can you give us a percentage of your feedstock that is the advantage of feedstock like the waste oil and all that? And also then, when we're looking at your renewable on the CST supply contract, I think you generate quite a fair amount of the RIN there. And can you tell us that, I mean, how much is the win you generate from those contracts and when that will expire? And when you talk about, I think, Martin, on the CCS band opinion in the ethanol, so that's related to eight of your plan out of the 16? So should we assume that half of your throughput volume will get that benefit of the $0.47 per gallon of the credit if we assume the LCFS maintained at 200? So that's the first question? Should I go ahead and – before I ask the second?
Well, but we're trying to figure that one out. But you're going to have to wait for even the second part of the first question.
That was good.
On the feedstock, DGD 2, I mean, we're expecting – we're going to have a higher mix of tallow, but we still expect the feedstocks for DGD 2 to be advantaged. So it's the same cast of characters, the used cooking oil, the tallow, the distiller’s corn oil of ethanol plants. So that's what we expect to be stock for DGD 2 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.
So what's – and then the ethanol question is, what was that carbon sequestration? How much of our volume is – what we're planning – what we're looking at, certainly, there's been a few questions the California market can't absorb it all. And 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 by the time we have these sequestration projects to be in place, something is going to happen in the Northeast. New York is a big market. As we said, New Mexico has 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 rigs look like on carbon sequestration. But again, we just feel like there is going to be more of these clean fuel standards, low-carbon fuel standard in the future than they are now. So we'll see how that plays out.
How about the CST supply contract on the wind generation and when that those contracts expire?
I don't think we can comment on that, unfortunately, Paul.
Okay. The second question is on Mexico. Given the recent political situation look like AMLO may want to be national lines or that we emphasize the stay maybe the dominancy in some of the sector including energy. So, 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, when we look at Mexico, first off, they would take a constitutional reform for them to really formally close out the energy sector and nationalize it. So, we don't see the political climate supporting that. If you're talking about the recent legislative reforms that Mexico is working on, those are really aimed around 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. And we think we have a pretty good relationship with them and a good relationship with PEMEX. And so our view is that 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 I've got eight questions. The bad news is I've got eight questions, Joe. The good news is you've answered six of them. So…
We've missed you, Paul.
I missed 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 refineries – 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 some of the stuff that's kind of damaging the market, particularly into New York Harbor. And that will be it for me. Thanks, guys.
Thanks, Paul.
Yes, Paul. So I think 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 record levels of imports. But you're already starting to see those odds close and the volumes of product flowing from Northwest Europe and the New York are slow. In addition to the slowing of imports, we're starting to see exports pick back up. So certainly, for us, we had exports down in the first quarter as we replenished inventories, but already in April. 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.
Anything to add on refining shutdowns, the outlook?
Yes, Paul. I would just say we've had a strategic outlook that says the EU, the southern refineries and 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 they are going to continue to be under pressure. And then we also believe and continue to have a sort of an outlook that Latin American refineries are going to struggle to run a competitive utilization rates. And so that's just going to be an ongoing thing. So to the extent that 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 on partnerships on the RNG side. Is this something that you've looked at? Or do you view it as not fitting or competitive within your portfolio compared to the carbon capture of renewable diesel projects? And then maybe a second one, you've got the Pembroke Cogen unit and the Diamond pipeline expansion coming on into the second half of this year. There's an EBITDA range associated with those, which is 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?
Okay. This is Rich Lashway. I'll take the first piece of the RNG. So we are looking at different opportunities where we can take the RNG on a kind of a booking claim basis into the refineries to generate the development fuels, which fit 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 kind of our supply chain to lower the carbon intensity of the products that we're producing. So we are doing it, but we're just kind of on a quieter kind of scale.
As for the Pembroke Cogen, we expect to start up here at the end of the second quarter, start of the third quarter. I think our FID EBITDA was like, I want to say, US$38 million. Obviously, you had some currency risk in that. But I mean that's sort of the range in terms of what the EBITDA contribution is on an annual basis. And…
Have a pipeline we don't have anything to add.
Yes. That was just an optimization and the return on that, Ryan, is going to be similar to like any logistics projects.
Great. Thanks, gentlemen.
The next question is from Jason Gabelman of Cowen. Please proceed with your question.
Yes. Hi. Good morning everyone. I wanted to ask on the refinery utilization guidance, specifically in the U.S., so 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 RINs. Do you expect prices to come off when RVOs 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.
So this is Lane. I'll speak to the first question about the outlook. It's somewhat commensurate with where we are today and like all-in 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 completely – we're not completely running at max because we are still being very careful with our supply chain.
Yes. And then on the – 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 veg oil 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 RINs 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. And being from my opinion on it, you just generated less deficits out there. So 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 the LCFS prices to rebound and that should be happening in the second and 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.
Hi. 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?
Yes. 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 is capital cost or energy costs, all of the above to try to make it. So if you sort of say, hey, I can always – I have the investment to make renewable diesel, therefore, I need something additional to make sustainable aviation fuel. Today, 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 the fractionation. So there's some costs there. And those are the things that these are the projects we're trying to develop where you certainly need just – you do need some – 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 over the hump here of requiring jet fuel to be a renewable.
Great. Thank you.
There are no additional questions at this time. I would like to turn the call back to Homer Bhullar 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.