Valero Energy Corporation (NYSE:VLO) Q1 2022 Earnings Conference Call April 26, 2022 10:00 AM ET
Homer Bhullar – Head of IR
Joe Gorder – CEO
Gary Simmons – EVP and Chief Commercial Officer
Lane Riggs – President and COO
Jason Fraser – CFO
Martin Parrish – Senior Vice President
Conference Call Participants
Doug Leggate – Bank of America
Roger Read – Wells Fargo
Phil Gresh – JPMorgan
Connor Lynagh – Morgan Stanley
Paul Cheng – Scotiabank
Theresa Chen – Barclays
Paul Sankey – Sankey Research
Manav Gupta – Credit Suisse
Neil Mehta – Goldman Sachs
Sam Margolin – Wolfe Research
Ryan Todd – Piper Sandler
Jason Gabelman – Cowen
Greetings. Welcome to Valero Energy Corporation’s First Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. [Operator Instructions] Please note this conference is being recorded.
At this time, I’ll now turn the conference over to Homer Bhullar, Vice President, Investor Relation and Finance.
Mr. Bhullar, you may now begin.
Good morning, everyone, and welcome to Valero Energy Corporation’s first quarter 2022 earnings conference call. With me today are Joe Gorder, our Chairman and CEO; Lane Riggs, our President and COO; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive President and Chief Commercial Officer; and several other members of Valero’s senior management team.
If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com.
Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.
I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company’s or management’s expertise 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. I’m pleased to report that today, we delivered solid financial results for the first quarter, led by a continued recovery in our Refining segment. Refining margins were supported by strong product demand, coupled with very low product inventories globally. Refinery capacity rationalizations that have taken place in the last couple of years continue to contribute to the supply tightness.
In addition, high natural gas prices in Europe are supporting product cracks to compensate for the higher operating costs.
This, in turn, provides a structural margin advantage for U.S. refineries particularly those located in the Gulf Coast, where natural gas costs are significantly lower than in Europe.
Turning to our low-carbon segments. The ethanol business generated positive operating income despite a weak margin environment and our growing renewable diesel business continues to generate good results with high demand for renewable diesel. We expect low-carbon fuel policies to continue to expand globally and drive demand for low-carbon fuels. And with that view, we’re leveraging our operational and technical expertise that steadily expands our competitive advantage.
The DGD 3 renewable diesel project located next to our Port Arthur refinery is now expected to be operational in the fourth quarter of 2022. With the completion of this 470 million-gallon per year plant, DGD’s total annual capacity is expected to be approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha.
BlackRock and Navigators large-scale carbon sequestration project is progressing on schedule and is expected to begin start-up activities in late 2024. Valero is expected to be the anchor shipper with 8 ethanol plants connected to this system, which should provide a lower carbon intensity ethanol product and result in higher product margins.
We continue to evaluate other low-carbon opportunities such as sustainable aviation fuel, renewable hydrogen and additional renewable naphtha and carbon sequestration projects.
And in refining, the Port Arthur Coker project, which is expected to increase the refinery’s utilization rate and improved turnaround efficiency, is still expected to be completed in the first half of 2023.
On the financial side, we remain committed to our capital allocation framework, which prioritizes a strong balance sheet and an investment-grade credit rating. We further reduced our long-term debt by $750 million in February through debt reduction and refinancing transactions, bringing our total long-term debt reduction to $2 billion in 6 months.
And we continue to honor our commitment to stockholder returns with an annual target payout ratio of 40% to 50%. We restarted stock buybacks in the first quarter which, combined with our dividend, returned $545 million to our stockholders.
Looking ahead, the fundamentals that drove strong results in the first quarter, particularly in March, continue to provide a positive backdrop for the refining segment. We expect product demand to remain healthy with light products demand near pre-pandemic levels and the pent-up desire to travel and take vacations should drive incremental demand for transportation fuels as we head into the summer.
Global product inventories remain low, particularly for diesel and there’s less refining capacity available to replenish inventories.
In addition, natural gas price disparity between the U.S. and Europe should provide a structural margin advantage for U.S. refiners especially for assets located in the Gulf Coast.
In closing, we’re encouraged by the refining outlook, which, coupled with our growth strategy and low-carbon fuels should further strengthen our long-term competitive advantage and drive long-term stockholder returns.
So with that, Homer, I’ll hand the call back to you.
Thanks, Joe. For the first quarter of 2022, net income attributable to Valero stockholders was $905 million or $2.21 per share compared to a net loss of $704 million or $1.73 per share for the first quarter of 2021.
First quarter 2022 adjusted net income attributable to Valero stockholders was $944 million or $2.31 per share compared to an adjusted net loss of $666 million or $1.64 per share for the first quarter of 2021.
For reconciliations to adjusted amounts, please refer to the financial tables that accompany the earnings release.
The refining segment reported $1.45 billion of operating income for the first quarter of 2022 compared to $592 million operating loss of the first quarter of 2021.
First quarter 2022 adjusted operating income was $1.47 billion compared to an adjusted operating loss of $506 million for the first quarter of 2021. Refining throughput volumes in the first quarter of 2022 averaged 2.8 million barrels per day, which was 390,000 barrels per day higher than the first quarter of 2021.
Throughput capacity utilization was 89% in the first quarter of 2022 compared to 77% in the first quarter of 2021.
Refining cash operating expenses of $4.73 per barrel in the first quarter of 2022 were $2.05 per barrel lower than the first quarter of 2021, which were impacted by excess energy costs related to winter storm Uri.
The renewable diesel segment operating income was $149 million for the first quarter of 2022 compared to $203 million for the first quarter of 2021. Renewable diesel sales volumes averaged 1.7 million gallons per day in the first quarter of 2022, which was 871,000 gallons per day higher than the first quarter of 2021. The higher sales volumes were attributed to the fourth quarter 2021 start-up of the Diamond Green Diesel expansion project or DGD 2.
The ethanol segment reported $1 million of operating income for the first quarter of 2022 compared to a $56 million operating loss for the first quarter of 2021. Ethanol production volumes averaged 4 million gallons per day in the first quarter of 2022, which was 483,000 gallons per day higher than the first quarter of 2021.
For the first quarter of 2022, G&A expenses were $205 million and net interest expense was $145 million. Depreciation and amortization expense was $606 million, and the income tax expense was $252 million for the first quarter of 2022. The effective tax rate was 21%. Net cash provided by operating activities was $588 million in the first quarter of 2022. Excluding the unfavourable impact from the change in working capital of $722 million and the other joint venture members, 50% share of Diamond Green Diesel’s net cash provided by operating activities, excluding changes in DGD’s working capital, adjusted net cash provided by operating activities was $1.2 billion.
With regard to investing activities, we made $843 million of capital investments in the first quarter of 2022 of which $536 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $307 million was for growing the business. Excluding capital investments attributable to the other joint venture members, 50% share of Diamond Green Diesel and those related to other variable interest entities, capital investments attributable to Valero were $718 million in the first quarter of 2022.
Moving to financing activities. We returned $545 million to our stockholders in the first quarter of 2022, with $401 million paid as dividends and $144 million of stock buybacks, resulting in a payout ratio of 44% of adjusted net cash provided by operating activities for the quarter.
With respect to our balance sheet, we completed debt reduction and refinancing transactions in the first quarter that reduced Valero’s long-term debt by $750 million.
As Joe already noted, these debt reduction and refinancing transactions, combined with the debt reduction and refinancing transactions completed in the third and fourth quarters of 2021 have reduced Valero’s long-term debt by $2 billion.
At quarter end, total debt and finance lease obligations were $13.2 billion and cash and cash equivalents were $2.6 billion. The debt-to-capitalization ratio, net of cash and cash equivalents was 34%. And we ended the quarter well capitalized with $4.9 billion of available liquidity, excluding cash.
Turning to guidance. We still expect capital investments attributable to Valero for 2022 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About 60% of that amount is allocated to sustaining the business and 40% to growth. About half of the growth capital in 2022 is allocated to expanding our low-carbon businesses.
For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.64 million to 1.69 million barrels per day; Mid-Continent at 395,000 to 415,000 barrels per day; West Coast at 225,000 to 245,000 barrels per day; and North Atlantic at 445,000 to 465,000 barrels per day.
We expect refining cash operating expenses in the second quarter to be approximately $5.15 per barrel which are higher than last quarter primarily due to higher natural gas prices.
With respect to the renewable diesel segment, we now expect sales volumes to be approximately 750 million gallons in 2022 with the anticipated start-up of DGD 3 in the fourth quarter.
Operating expenses in 2022 should still be $0.45 per gallon, which includes $0.15 for noncash costs such as depreciation and amortization.
Our ethanol segment is expected to produce 4 million gallons per day in the second quarter. Operating expenses should average $0.48 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization.
For the second quarter, net interest expense should be about $140 million and total depreciation and amortization expense should be approximately $630 million.
For 2022, we expect G&A expenses, excluding corporate depreciation, to be approximately $870 million.
That concludes our opening remarks. [Operator Instructions]
[Operator Instructions] Our first question comes from the line of Doug Leggate with Bank of America. Please proceed with your question.
This one might be for Gary, actually or whoever, Joe, you want to allocate it to. But I’m curious about the cadence of the margin trajectory, realized margin trajectory through the quarter. Obviously, the world kind of changed at the end of February. But what we’re trying to really get a handle on is what the kind of sustainable earnings momentum might look like, given what we saw in March and obviously, stronger crack indicators again in April. So that’s my first question, the cadence of margins through the quarter and what it looks like in April so far.
Yes, Doug. So I would tell you, in the first quarter, we saw is really pretty strong distillate demand throughout the quarter. But to start first quarter, gasoline demand was a little bit soft. We had a wave of COVID go through, which impacted mobility. And so the quarter started with a little softer gasoline demand but it recovered rapidly throughout the quarter. So by the end of the quarter, we were seeing gasoline demand at or slightly above pre-pandemic levels. We are seeing distillate demand above pre-pandemic levels and that demand being met with significantly less refinery capacity as we had rationalization that occurred during the pandemic. So, really tight supply demand bounce and then very, very low product inventories. .
So we’re looking at a situation where total light product inventory is 41 million barrels below the 5-year average. So very, very tight, especially tight for diesel. Diesel inventories in the U.S. 27 million barrels below the 5-year average. So the strength in crack spreads really been led by diesel. As long as inventories remain low, you would expect that to translate into very strong refining margin environment. And in fact, so far in April, we’ve seen stronger margins than we even had in March.
What we expect to see throughout the quarter is ultimately, as we get into driving season and gasoline demand continues to pick up, you’re going to have to have compression between gasoline cracks and diesel cracks.
A lot of the VGO that comes into the United States to fill conversion capacity West source from Russia. So VGO is tight. And we’re going to have competition between an incremental barrel going to an FCC to make gasoline versus that barrel going to a hydrocracker to make diesel. So we would expect gasoline cracks to get stronger as we move through the second quarter.
Sorry, Gary, to press you on this, but maybe I’ll ask it like this, how much of the earnings in the quarter from refining were in March?
Doug, we can’t give you a breakdown of earnings. But I think as Gary highlighted, obviously, March was a significant contributor.
Okay. Sorry for trying. My follow-up is really on Joe’s prepared remarks about structural cost advantage. Joe, I think you know where we stand on this. Our view is that the U.S. has moved into almost like a regional golden age given your structural cost opportunities and the rationalization of capacity here. I’m wondering if you could just offer us some color on how we quantify the — whether that advantage looks like given you’ve got Pembroke as a benchmark relative to the U.S. What is the delta right now? And do you see — what would you hazard guess at as kind of normalized go-forward spread between U.S. and European gas as it relates to refining?
Yes, Doug, that’s a good question. Let’s let Lane take a whack at it here.
Yes. So as you alluded to, we have the Penbrook refinery, so we have a little bit of insight on this. So if you sort of today, our natural gas prices over in the U.K. are roughly about $30 per million BTU, sort of look at the United States and we’re currently paying somewhere between $5, $6, $6.5. If you specifically use $30 versus $5, you need about an $8 per barrel higher heat crack sort of breakeven — Pembroke to breakeven versus the Gulf Coast asset.
And is that kind of ratable as we — if we normalize the long end of the curve right now, it shows about a $5-plus spread per Mcf. So that would just be kind of ratable so would be like $1.5 or something like that way?
Well, I’m not quite following what I would say is you split the burden of saying, “Hey, I get this – what he cracked do I need from Pembroke versus the Gulf Coast, I need about an $8 per barrel higher heat crack. If I’m paying $30 per million BTU for gas in the U.K. versus sort of $5 in the U.S.
Our next question is from the line of Roger Read from Wells Fargo. Please proceed with your question.
Probably a little bit to follow up on how we think about the second quarter here and capture and kind of contrast that with the guidance on volume. So the guidance on volumes would imply some more maintenance going on this quarter. So as we think about higher crude prices, lower secondary box I’ll call it, kind of stratospheric diesel cracks and how we should think about the moving parts here affecting capture for you all.
Yes. This is Lane. So I’ve sort of been talking about this as we’ve been on the road. I mean it’s very difficult right now to sort of compare previous capture rates versus the index as they are today. As you said, first and foremost, it’s backwardation the crude markets and the product market. Secondarily, it’s our secondary products like propylene and pet coke and asphalt and others that don’t move quite as fast as crude has moved up in price. And of course, finally, we had quite a bit of turnaround activity in the first quarter. We’re giving our volume guidance in terms of how the second quarter looks, but I think going forward, as long as there’s this much backwardation in the market, we’ll make — trying to figure out what the margin capture is going to be on a go-forward basis, a little more difficult.
Well, at least you got plenty of room to work with given where the crack spreads are. A follow-up question. So end of the quarter cash, if I remember correctly, was $2-something billion. Joe, at the last management meeting at the beginning of April, you talked about maybe being more comfortable or you did, maybe, Jason, to carrying $4 billion of cash. You restarted the share repos here in Q1. Presumably, those will keep going. What’s the right way to think about maybe hitting the upper end of the 40% to 50% or exceeding the $50, do you want to get to the 4 billion in cash first is it more to debt to pay down? Just kind of walk us through before what we should think about as we think about better-than-expected cash flows, I think most of us had coming into the year and how that may play out as we go through the rest of this year.
This is Jason. I’ll take a shot at it. No, you’re right, you hit our three goals, which we’ve talked about, and we’ll try to do simultaneously. We want to build up cash. We want to continue to pay down debt. We paid down $2 billion over the past 6 months. And also to — definitely on our commitment to our shareholders with the buyback.
So I believe with what we did in the first quarter, we were at about 44% on the share buybacks with regard to the payout ratio, and we will still look at it on an annual basis. And you said we’re at 2.6 on cash. So we’re not even at — we talked about having at least three probably going forward as a minimum, of course, it will vary around, but that’s kind of what we’re looking at. So we’ll build some more cash. We don’t have any maturities coming due, while we have a small one next quarter, but we’ll be looking at opportunistic to get repurchases as we move forward.
Yes. So we’ll try to do them all simultaneously. We don’t have an order where we’ll get up to $4 billion of cash before we do X or anything like that.
Roger, the only thing I’d add to what Jason said is we live one day at a time in this business for sure. But if you look at what we’re looking at in the market today, you feel pretty comfortable with the ability to go ahead and achieve all those things that we mentioned, building some cash as we go forward, we thought it was opportunistic to buy back shares with the outlook that we had for the market going forward. And so we went ahead and did it, and we’ve got our commitment to honor the payout ratio target. And so Jason said it right. We’re looking at doing all three of them simultaneously. But I guess what it speaks to from my perspective is kind of the general outlook that we have on the market going forward and that we’re going to be able to achieve all of these three things with the way things appear to be right now.
Our next question is from the line of Phil Gresh with JPMorgan. Please proceed with your question.
One follow-up to that, just as we think about the balance sheet and the fact that you effectively approach the leverage target side of the equation. If this is a really strong environment or a peakish type of year, would you consider moving the leverage target lower? A lot of question marks out there, recession risk or other things. Just curious how you’re thinking about kind of managing through cycles from leverage.
Yes, this is Jason. We’re pretty comfortable with our 20% to 30% range. It definitely gives us range to get a lot lower than we are now. I believe we’re at 34% now. So we still got a little ways to get down to our — the upper end of our target. And of course, we can do that by holding cash or paying down debt. So we’ll look at both of those tools. But yes, I mean I think we’re comfortable with the range and it gives us a lot of flexibility within it.
And then just on DGD I think you’ve talked about a go-forward capture rate there on the gross margin, somewhere around 100%. The capture rate was definitely better in 1Q relative to some of the headwinds in 4Q. I was just curious if there were any other headwinds there in 1Q to think about that might have been transitory and just how you’re thinking about the go-forward margin outlook?
Phil, this is Martin. You’re right. The capture rate improved in 1Q versus 4Q. 4Q, the issue was really feedstock costs relative to soybean oil and actually priced above soybean oil or feedstock. And as we talked about before, that was largely due to the DGD 2 getting into the pit changing feedstock flows. And every time we’ve done that in the past, when we’ve expanded, we’ve seen feedstock prices go up. The good news in the first quarter is feedstock prices moderated relative to soybean oil actually, they ended the quarter below soybean oil. So that all looks good.
So the — what impacted margin capture in the first quarter was really the backwardation that Lane’s talked about that prompt crack is just not achievable. So that was the issue. So it’s really the backwardation in the ULSD market that impacted the capture. And as long as we have that backwardation, we’ll have — will lag on the capture but that won’t be a permanent thing.
Our next question is from the line of Connor Lynagh with Morgan Stanley. Please proceed with your question.
Just high level on distillate and distillate inventories. I mean, do you attribute the supply tightness entirely to what’s been happening in Europe either on the natural gas cost side of things or the outright disruptions in Russia? Or do you feel there’s some sort of bigger global issue here?
Well, I think it’s a number of factors. But certainly, as I alluded to, distillate demand has remained fairly strong throughout the pandemic, and you’re trying to supply that demand with less refining capacity as we’ve had rationalization occur in the industry. I think you couple with the fact that we came through a period of time where there was a lot of maintenance activity. People trying to catch up from maintenance that maybe didn’t occur during the pandemic. So you saw low refinery utilization.
And then you add to it the natural gas presenting challenges in Europe and less Russian distillate flowing into the market as well, and it kind of puts us in the position where we’re in.
I guess the — we’re sort of driving at this is as we look into summer driving season and presumably further recovery in jet demand, is there a slack that you guys see in the global refining system or in the U.S. refining system to really significantly increase runs and refill those inventories? Or do you think we need to see some sort of demand destruction to balance the market?
It’s hard to see that refinery utilization can increase much. We’ve been in this 93% utilization and historically although we’ve been able to hit 93% utilization, generally, you can’t sustain it for long periods of time. So I don’t think there’s a lot of room on refinery utilization in terms of increasing supply. I think the markets will have to balance more on the demand side. .
And just to sneak one more. And do you think that’s more likely on the gasoline diesel or jet side? Or how would you think about that in terms of product?
Well, I think it depends. In the domestic market, it looks like jet demand is recovering nicely. Certainly, you’ll have an impact to international travel still with COVID restrictions in place, some places and then high prices impacting some air travel as well. Gasoline and diesel seem very constructive and a lot of it is — we have still a lot of pent-up demand. People that have been unable to travel for a couple of years are ready to go out and take vacation. And so in our mind, we’ll see very good demand continue for both gasoline and diesel. .
Our next question is from the line of Paul Cheng with Scotiabank. Please proceed with your question.
Actually, you mentioned earlier about the backwardation curve. I think we all understand how the crew market deputation curve will impact on the margin capture. I’m not sure I fully understand how the port up backwardation curve will impact on the margin capture or the profitability. Can you maybe help me understand a little bit better on that? That’s the first question.
And so I’ll take a shot and maybe Gary can firm it up. When you’re trading in the cycle, right, if the crack is rolling up towards you and you’re out there sort of selling into it, you’re not necessarily capturing the peak number all the time. It’s just — we’ve had days where the diesel crack has gone up $0.20 a gallon, $0.30. So you’re not going to hit it perfectly. And of course, since we raised a ratable book and we’re sort of fully hedged, there again, it’s a little bit more difficult for us to fully capture a steeply backward distillate market. .
Does that mean that your vehicles in a commercial market your category will benefit?
Yes, for products. Yes, what structure is telling you is that the world is short, right? It’s either short — that’s what structure is telling you. So yes, your commercial alarms actually do pretty well in a contango market. It’s just the underlying crack is not necessarily as good as you would like.
And in the crude market, this is in [indiscernible] or contango, I mean, we can pretty much do a relatively easy estimate? What’s the impact from the CMA. Is there any rule of thumb that is the variation curve in the product market? Is it a dollar to dollar impact on your margin capture or not really is a fraction and it is a fraction, is there any from what percentage that may be?
No, it’s not as transparent because so many of our barrels are essentially brent-based. And so we have to look at the overall sort of dated market and sort of how we build up to get from sort of the physical market to an ICE relationship. So it’s a little not as transparent, and it’s not as easy to see, but you can — obviously, you can look at what something similar to the complex role of that to see. Is it really — is it a — it’s actually backward or not? And then just look have to sort of come up with how you guys want to model that. .
The second question is on the Russian innovation and correspondingly I mean there’s a lot of moving parts. I mean, the European gas price is high, the feedstock availability on video or those have become reduced. And we’ve also seen, of course, that the product export from Russia in gas oil to Europe has been dramatically reduced. So how that your operation in Europe, Pembroke and also maybe that your Gulf Coast refining operation had been changed or more and adopt to this new, I mean, is the product yield had been any meaningful differences because of the market condition or the current situation that we see.
And also that because you no longer can buy the M100 when you purchase the other similar type from Latin America or Middle East how that impact on your product yield on your operation?
Again, I’ll say, hey, Paul, I’ll take a shot and Gary can correct anything that I say that’s not exactly correct. .
So starting with the first item, VGO definitely, when you look at how the Russian balances were VGO is essentially — they’re the final sort of exporter of a major — a major physical supply of VGO to the market. And so we’ll just have to see how that plays out. Today, it’s not because the diesel crack is so high versus gasoline, you’re still in that diesel. I mean Gary kind of touched upon it earlier. I think our anticipation is as you get more into the driving season, as you — you sort of — you enter into a period where maybe it’s a little more difficult to fill up these conversion units because of the availability of gas. You’ll have to start bidding molecules away from the distillate market. And as long as the distillate market remains tight, it is just going to keep pulling up both cracks. We’ll just have to see how that works out.
With respect to our M100 supply, we’re out buying sort of replacement barrels in the areas that you alluded to, which is largely the Middle East and South America. We’d have been buying those in the base if they were the most economic or we’ve certainly been able to certainly shore up our supply situation with those with barrels from those areas.
But in the dose barrel when you run through your refinery, do they yield differently or do you need to change the way how you operate?
Well, we’re blending differently, right? So what it means is — because, yes, all these feedstock even M100 has variability from different areas and all these intermediates have different variability and qualities. And we’re always — I mean that’s part of the sausage making. We figure out how to blend to something that we think is the most economic for us to run.
Our next question is from the line of Theresa Chen with Barclays. Please proceed with your question.
I have a follow-up question, Lane, on some of the comments around demand and gasoline. Clearly, there’s a lot of concern on demand currently and much of that is driven by factors abroad that’s outside of your control. But I was hoping if you could offer your thoughts on how elastic do you think that demand curve is currently. And you’re already in like a tight product supply situation due to rationalization alone. And now the Russian VGO is coming out of the market. And to your point, the gas crackers, you just incentivize that barrel of VGO from the hydrocracker, which means that gasoline cracks need to go higher and if crude doesn’t go lower prices used to go higher. So how does all that shake out as far as the demand picture goes for you?
Theresa, this is Gary. So it’s difficult to tell at what price point do you see demand destruction on gasoline. I think there’s a number of factors that come into play there. Certainly, you would expect elevated price to have an impact on demand. However, we’ve seen wage inflation that kind of offsets that and allows people to tolerate a higher price point with personal savings up again, people pent-up demand. They’re going to want to travel and they have money in the bank. So it probably offset some of that to some degree.
And then throughout the world, not so much in the U.S., but in many other countries, we’ve seen the government step in, in the form of tax subsidies ways to kind of offset those increases and keep the street price down. So I think a lot of those factors will kind of offset some of the things that we typically see and that would cause the demand destruction to occur on gasoline.
And just on the export side, what are you seeing in terms of the competitive dynamics in the export markets? Clearly, you’re well positioned given your geographical concentration in the Gulf Coast. How do you see the market evolve or Gulf Coast refiners as domestic supply has rationalized to some extent, and LatAm continues to grow over time. There seems to be a structural bid for diesel into Europe, given their shortage. How do you see these factors playing out?
Yes. So I think as long as you know, when you look at the advantages, the U.S. Gulf Coast refining system has — we’ve talked a lot about natural gas, but also feedstock cost advantages running domestic crude or Canadian or Mexican crude. It puts us in a very strong position to be able to compete globally into the export markets. And I think you’ll see that continue. PADD 3 is long diesel. And so you’ll see that length move into the export markets, Latin America and Europe throughout the summer.
Our next question is coming from the line of Paul Sankey with Sankey Research. Please proceed with your question.
These are have much follow-up questions. Pretty much follow-up questions, given everything you said. Just specifically, do you have a number for how much Russian crude and I guess, VGOs into media and then Russian products that is now out of the market further to what you’re saying. And it seems that you’re saying that trade remains strong despite the strong dollar and the high prices. And the follow-up would be on the working capital movement, how is the environment affecting your trading and markets in general because we’re all aware that there’s been a falling off of open interest. I assume that the working capital commitment will stay high as long as prices stay high. But if there’s anything you can add on what it means for markets, that would be very helpful.
Yes. So I guess to start with, we have seen — it looks like diesel coming out of Russia and M100 coming out of Russia have fallen off. Thus far, we haven’t really seen the fall off in crude exports from Russia. So far, it looks like it’s been more of a rebalancing of trade flows rather than a reduction in exports. You can see India taking more Russian barrels, China taking more Russian barrels. Some Latin grades in West African grades flowing into Europe.
And then in here in the United States, you’re seeing a more Brazilian and Colombian grades that we’re going to India and China starting to flow in the U.S. So I don’t know that we’ve seen so much on the crude export side, but certainly on the M100, the resids and the distillate, you’re starting to see export fall off. Working capital discussion
Paul, this is Lane. I’ll take a shot at it. This is what you’re trying to get at. One of the things that you’ve seen in the working capital ideas is that with this tiny traded derivatives market, the paper markets, it’s sort of is trying — what you’re seeing is the trading companies and the operating companies are trying to sort out who’s going to have the physical length that’s going either across the Atlantic or to South America, depending on trade flow, and it’s because there’s just — this volatility is an derivative market. And so everybody is trying to — that’s still being sorted out, I guess, is the best way I would say that. .
If I just sneak in a quick follow-up. Your light sweet crude, they look like they are an all-time record high at the moment, right?
Yes, they are.
Our next question is from the line of Manav Gupta with Credit Suisse. Please proceed with your question.
I’m going to try for one. I’m not sure if I get the answer, but it’s my job to try. So if we go back a decade, 2015 was the best year in earnings. And let me know how if I’m wrong, but I think you made over $9 in EPS in ’15. So when we move forward today, first quarter 2.31. The next two quarters, most of us who really believe in Valero believe there’s like an $8 or $9 EPS number hidden there combined for the 2 quarters. And then the last quarter is generally our strongest. So that’s another 2.50. We put all three things together this high that will be achieved in 2022 will be materially higher than the 2015 earnings number. If I’m thinking about it right, can you comment about how the management is thinking about a record high earnings in over a decade.
So Manav, I’ll just say that — I said it earlier, we live one day at a time. And we certainly like your thinking and your mindset. And frankly, I think everything you’ve heard from the team this morning is that things look constructive on all segments of our business right now. And so we’re optimistic, but we don’t cut our chickens before they’re hatched. So we’ll continue to do what we do, and that is coming every day and try to operate safely and reliably in an environmentally responsible way and to optimize to the extent we can. And if we just keep doing that day after day after day, I think we’re going to find ourselves in a really good place.
And one quick follow-up here is, every quarter, we see a very positive trend. DGD moves ahead by one quarter. And so if you spot that trend, the logical conclusion here is that on your 2Q call, you would basically say that we have achieved mechanical completion and we are starting the RD projects. I’m just sporting a trend here, sir. So let me know what you think about that.
Well, Martin, do you want to?
Well, obviously, we’ve got a long track record here and we — DGD 3 is pretty much a duplicate of two, just a little bit bigger. So that helped a lot, same construction teams, same contractors, perfect weather. So we got to get through hurricane season still, Manav, but yes, everything looks great over at Port Arthur.
Manav, the one thing that I would say, too, and we don’t talk about it a lot, but our team’s ability to execute major projects like this. I mean, Lane has really worked very hard on this over the years and our team’s ability to execute significant projects and the partners that we’ve got helping execute those prospects are extraordinary. And at least to the kind of results that you said look like a trend, and it’s a trend that we like and we’ll try to maintain.
Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.
First question is on the U.S. Gulf Coast. We’ve seen a lot of capacity retirement down there, whether it was Lyondell here recently, obviously, Shell can and then the alliance refining assets as well, something like 7% capacity is now out of the market as of next year. How do you guys see that impacting the structural outlook of the U.S. Gulf Coast? And what changes of that anything? Or is that market just so deep and interconnected that retirement doesn’t have a meaningful impact on the way you think about product basis?
Yes, I would say, overall, Neil, PADD 3 is an export market on both gasoline and diesel. So I wouldn’t expect to see a material impact from shutdown capacity in terms of the product market. We do see it gives us some advantages on the crude stock. We’ve certainly seen that as refineries come down, especially those refineries in the Eastern Gulf. It gives us access to some U.S. grades that maybe we didn’t have access to before.
And the follow-up is also on the product markets, and I just love your perspective on what’s happening in China right now. Certainly, it looks like a couple of million barrels a day, product demand could be down, but at the same time, China is not exporting product into the market in a meaningful way. And so Singapore margins continue to be very strong. But as you look at the balances here, — how much of a concern is China? And — do you think that, again, that impact could be contained because of inventory levels but also product quotas?
Well, Neil, I think it really — the answer is kind of in what you just stated. Thus far, although certainly, the COVID restrictions have impacted demand in China, they’re not exporting a lot of product. So I think if you had weak demand in China and high refinery utilization resulting in very high exports, that would be concerning, but we’re not seeing that in the market today. .
Our next question is from the line of Sam Margolin with Wolfe Research. Please proceed with your question
Question on capital allocation. A significant amount of your growth CapEx is low-carbon projects, and those projects come early, but they’re very regimented process. And just because a project comes early doesn’t mean the next one is going to start early. So you might develop kind of a lumpy pattern of growth CapEx. And I’m just wondering if that has an effect on your on the other elements of your capital allocation, the other components, return on capital or if you harvest that cash, what happens when you have maybe a lean year in growth CapEx just because of the cadence of your gated process.
So you’re saying if we have a year — in a lean year for growth CapEx, you’re talking about a year where we spend less on growth CapEx?
Yes, because if you finish DGD 3 early, it doesn’t mean you’re going to start the next one early as well, right, because you’re still going through the process for it. So you might have a gap in spending given the magnitude of your growth CapEx in that portion. .
No. Got you.
Okay. Sam, so it’s Lane. I’ll take a stab. So it’s an interesting idea. And I do think you’ll see our strategic capital and as well as our sustaining capital, we’ve always said that we guide to 2% to 2.5% on the overall capital budget, nominally 1.5%. These are all averages. So by definition, our strategic capital is going to be 0.5 billion to 1 billion normally on an average. And the — we are — it will be lumpier because they are sizable projects and so I think direction of that is true from — potentially from a year-to-year, I don’t think you’ll see us go from 0 to $2 billion or something like that, but you’ll certainly see a $0.5 billion of variability with respect to our strategic capital spend here in the near term. And you want to comment
Yes, it just fits in the bar with excess cash. I don’t think we’d change our model based on the variability and growth CapEx.
Yes. I mean Sam, I think it was mentioned earlier, Jason mentioned earlier, we haven’t yet achieved the three targets that we’re shooting for as far as the use of cash, whether it be the debt ratio buybacks and so on. So we’ve got a little bit of work to do around that yet, but building a little bit of cash that never is very troubling to us.
Yes. And this is sort of a follow-up, and it is kind of a hypothetical around DGD 4. We’re talking a lot on this call about clear evidence of a distillate shortage that’s driven by some structural factors. And so now you have a consideration for renewable diesel supply that goes beyond just policy and the regulatory framework because we just need more diesel period, renewable or otherwise. And so I’m wondering if that’s a consideration that’s now going into the commercial analysis behind incremental R&D projects.
Yes, Sam, this is Martin. I’m not sure we’ve looked at it that way. But overall, I would just tell you the demand for renewable diesel, we look at the balances, we just think that demand is going to outstrip supply. And we’ve got a lot of speculation is coming on. We’ll see how much of that happens. But we feel good about supply, the European demand for renewable diesel. We feel good about demand. Demand for renewable diesel in Europe is going to rebound a lot with no more COVID lockdowns has been the case. So we got RED 2 out through 2030 and we’re talking about in the Fit for 55 program, what they’re going to do for the RED 3 is pretty aggressive. So — and then California, Oregon, Washington, the CFS in Canada. So we just see a lot of demand out there.
Our next question is from the line of Ryan Todd with Piper Sandler. Please proceed with your question.
Maybe just a couple of high-level strategic ones. I mean, clearly, we’ve talked a lot here about how attractive the setup is for the rest of this year with markets that can tight and margins strong. Outside of a potential recession, what risks do you worry about that could materially change the outlook, Joe?
Well, I mean, if we ended up in a huge recession, I think those are the kind of things that certainly are out of our control, but it would likely affect demand. And another bout of COVID that would shut down people’s mobility would impact us. But outside noncontrollable factors like that right now, I mean, I just — I think we’re generally pretty bullish about the way things look. You add anything?
No. I mean, those comments are right. I mean we didn’t at least — I do think people — my own personal — I think people’s tolerance of COVID is a little different than the last time. So I don’t know that we’ll see the demand destruction COVID sort of some form of variant of COVID comes running through for whatever reason. But the recession has to be our biggest risk at this point. .
Right. And then maybe it feels like it’s been a long time since you’ve been in the market for the purchase of refining asset. But I wonder if you have any comment on developments in the refining asset market. Particularly, we have news of a failed sale process for the Lyondell refinery. Is this just a gap in bid-ask range you’re seeing? Or do you see it as increasingly difficult for large assets to transact going forward? And if that’s the case, what does it mean for medium- to longer-term supply/demand balances globally? Is this — are we more likely to see more closures versus sales going forward in keeping markets tighter than they might be otherwise?
Well, I mean, probably the safest way for us to talk about that is from our own perspective. And there haven’t been assets in the market that were compelling for us to buy. That doesn’t mean there aren’t attractive assets that we’d be interested in. But with our experience in acquisitions of assets, you go through the periods of being super enthusiastic about it, and then you get deal heat, you want to go do it and then you buy it and then you get in there and you start looking at it and Lane tells me it’s going to cost $3 billion to get it up to a Valero standard, and I look at it maybe that wasn’t exactly the best thing.
So for us, truly, it is simply a matter of asset allocation, Ryan. I mean where do we want to spend our money. And right now, it’s not that these assets aren’t good or aren’t attractive. It’s just we feel we’ve got higher return, better uses for the capital we want to employ than buy on a refinery that’s on the market at this point in time. So I’ll stop there. Anything you would add, you guys.
This is Lane. I do think what it does mean is that you potentially versus transacting a large refinery or even certainly smaller ones, the likelihood that they may shut down is probably direct. At least directionally versus the past is more likely and that’s what we’re seeing.
Our final question this today comes from the line of Jason Gabelman with Cowen. Please proceed with your question.
I have two. The first will be a follow-up on the refining margin outlook. We’re getting a lot of inbounds asking how long this strong margin environment can last and you’ve obviously been very bullish on the call. But maybe a couple of near-term things we’ve seen that I was hoping to get your comment on. One is the kind of somewhat rapidly tightening spread between European gas prices and U.S. natural gas prices. Do you think that impacts the margin environment at all? Could you see Europe increase utilization on some of its secondary distillate processing units?
And then the other one is the IA suggesting that there could be a 5 million-barrel per day increase in refining throughput from now through summer as refining capacity, as maintenance comes back, which is kind of double the typical rate, I think you would see over that period. Just wondering if that factors into your bullish outlook on refining and if you expect either of those to weigh on the market at all? And then I have a quick follow-up on capital allocation.
So this is Lane. I’ll start off. Your first node of seeing it rapidly are closing the arbitrage between you say European gas and U.S. gas has — there’s a barrier there because these export facilities are full. So to the extent that, that will happen, you need to get some more export you got to get to where you have open capacity on the liquid natural gas facilities have to be, have open capacity to fully get there. And so you need to you kind of get a need to go out there and look at what pace and when the next ones are all being built.
In terms of refining — worldwide refining capacity and how we think about it, we keep saying all along, we don’t spend a lot of time trying to figure out what the rest of the world is doing on this. You guys have the same data that we have. We focus on doing what we do well, and that’s what we focus on.
With that said, I mean, there’s going to be refinery closures based on the rest of the call that we’ve talked about versus certain parts of the world are going to build refineries. And so but we don’t — we certainly — at least we don’t worry so much about how these balances are going to necessarily affect us.
And then just a quick follow-up on capital allocation moving forward. It seems like you have this coker project and then after that, no major refining projects, but you’ve been discussing some other low-carbon energy investments. Is the intention for over time, more of the growth capital or nearly all of it to kind of gravitate towards that low-carbon bucket?
I wouldn’t say that by any stretch. I mean, we — you know our MO, right? We talk about stuff after we fully developed it, understand how much it’s going to cost and have a good feel for the market. And so I think it’s fair for you to assume that Lane and the team are looking at all the projects and we evaluate them against each other. I wouldn’t want to tell you that there’ll never be another refining project, but I can tell you a lot of the stuff that’s in the hopper that he and the team are looking at tend to be more towards the cleaner fuel side. But honestly, I would never say never on another great project.
Great. Thanks. Thank you, everyone. We appreciate you guys dialing in.
Valero Energy Corporation (NYSE:VLO) Q1 2022 Earnings Conference Call April 26, 2022 10:00 AM ET