(VLO)
Q3 2023 Earnings-Transcript
Valero Energy Corporation beats earnings expectations. Reported EPS is $7.49, expectations were $7.36.
Operator: Greetings, and welcome to the Valero Energy Corp. Third Quarter 2023 Earnings Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Chief Vice President, Investor Relations and Finance. Thank you. Please go ahead.
Homer Bhullar: Good morning, everyone, and welcome to Valero Energy Corporation’s third quarter 2023 earnings conference call. With me today are Lane Riggs, our CEO and President; Jason Fraser, our Executive Vice President and CFO; Gary Simmons, our Executive Vice President and COO; 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. Although attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted financial 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.
A modern seaborne tanker off the coast of a major metropolitan city, transporting liquefied petroleum gas.
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 earnings release and filings with the SEC. Now, I’ll turn the call over to Lane for opening remarks.
Lane Riggs: Thank you, Homer, and good morning, everyone. We are pleased to report strong financial results for the third quarter. In fact, we set a record for third quarter earnings per share. Finding margins were supported by strong product demand against the backdrop of low product inventories, which remained at 5-year lows despite high refinery utilization rates globally. The strength in demand was evident in our U.S. wholesale system, which matched the second quarter record of over 1 million barrels per day of sales volume. Our refineries operated well and achieved 95% throughput capacity utilization in the third quarter, which is a testament to our team’s continued focus on operational excellence. We continue to prioritize strategic projects that enhance the earnings capability of our business and expand our long-term competitive advantage.
The DGD Sustainable Aviation Fuel, or SaaS project at Port Arthur remains on schedule and is expected to be complete in 2025. Once complete, we expect the Arthur plant [ph] to have the optionality to upgrade up to 50% of its current of 470 million-gallon annual renewable diesel production capacity at SaaS. The project is estimated to cost $315 million, with half of that attributable to Valero. With the completion of this project, Diamond Green Diesel is expected to become one of the largest manufacturers of SaaS in the world. On the financial side, we honored our commitment to shareholder returns with a payout ratio of 68% of adjusted net cash provided by operating activities through dividends and share repurchases in the third quarter and we ended the third quarter with a net debt to capitalization ratio of 17%.
In closing, while there are broader factors that may drive volatility markets, we remain focused on things we can control. This includes operating our assets efficiently in a safe, reliable and environmentally responsible manner, maintaining capital discipline by adhering to a minimum return threshold for growth projects and honoring our commitment to shareholder returns. So with that, Homer, I’ll hand the call back to you.
Homer Bhullar: Thanks, Lane. For the third quarter of 2023, net income attributable to Valero stockholders was $2.6 billion or $7.49 per share compared to $2.8 billion or $7.19 per share for the third quarter of 2022. Adjusted net income attributable to Valero stockholders was $2.8 billion or $7.14 per share for the third quarter of 2022. The refining segment reported $3.4 billion of operating income for the third quarter of 2023 compared to $3.8 billion for the third quarter of 2022. Refining throughput volumes in the third quarter of 2023 averaged 3 million barrels per day, implying a throughput capacity utilization of 95%. Refining cash operating expenses were $4.91 per barrel in the third quarter of 2023, higher than guidance of $4.70 per barrel primarily attributed to higher-than-expected energy prices.
Renewable Diesel segment operating income was $123 million for the third quarter of 2023 compared to $212 million for the third quarter of 2022. Renewable diesel sales volumes averaged 3 million gallons per day in the third quarter of 2023, which was 761,000 gallons per day higher than the third quarter of 2022. The higher sales volumes in the third quarter of 2023 were due to the impact of additional volumes from the DGD Port Arthur plant, which started up in the fourth quarter of 2022. Operating income was lower than the third quarter of 2022, primarily due to lower renewable diesel margin in the third quarter of 2023. The ethanol segment reported $197 million of operating income for the third quarter of 2023 compared to $1 million for the third quarter of 2022.
Ethanol production volumes averaged 4.3 million gallons per day in the third quarter of 2023, which was 831,000 gallons per day higher than the third quarter of 2022. Operating income was higher than the third quarter of 2022, primarily as a result of higher production volumes and lower corn prices in the third quarter of 2023. For the third quarter of 2023, G&A expenses were $250 million and net interest expense was $149 million. Depreciation and amortization expense was $682 million and income tax expense was $813 million for the third quarter of 2023. The effective tax rate was 23%. Net cash provided by operating activities was $3.3 billion in the third quarter of 2023. Included in this amount was a $33 million favorable change in working capital and $82 million of adjusted net cash provided by operating activities associated with the other joint venture member share of DGD.
Excluding these items, adjusted net cash provided by operating activities was $3.2 billion in the third quarter of 2023. Regarding investing activities, we made $394 million of capital investments in the third quarter of 2023 of which $303 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $91 million was for growing the business. Excluding capital investments attributable to the other joint venture members share of DGD capital investments attributable to Valero were $352 million in the third quarter of 2023. Moving to financing activities. We returned $2.2 billion to our stockholders in the third quarter of 2023 of which $360 million was paid as dividends and $1.8 billion was for the purchase of approximately 13 million shares of common stock resulting in a payout ratio of 68% of adjusted net cash provided by operating activities.
This results in a year-to-date payout ratio of 58% as of September 30, 2023. With respect to our balance sheet, we ended the quarter with $9.2 billion of total debt, $2.3 billion of finance lease obligations and $5.8 billion of cash and cash equivalents. Debt to capitalization ratio, net of cash and cash equivalents was 17% as of September 30, 2023 and we ended the quarter well capitalized with $5.4 billion of available liquidity, excluding cash. Separately, as reported by Navigator last week, they cancelled their CO2 pipeline project. We still see carbon capture and storage as a strategic opportunity to reduce the carbon intensity of conventional ethanol, which would also qualify it as a feedstock for sustainable aviation fuel. Without carbon capture and storage, conventional ethanol does not have a pathway into staff under today’s policies.
We continue to evaluate other projects to sequester CO2. Turning to guidance. We still expect capital investments attributable to Valero for 2023 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About $1.5 billion of that is allocated to sustaining the business and the balance to growth. For modelling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.77 million to 1.82 million barrels per day; Mid-Continent at 445,000 to 465,000 barrels per day; West Coast at 245,000 to 265,000 barrels per day; and North Atlantic at 470,000 to 490,000 barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.60 per barrel.
With respect to the renewable diesel segment, we expect sales volumes to be approximately 1.2 billion gallons in 2023. Operating expenses in 2023 should be $0.49 per gallon, which includes $0.19 per gallon for noncash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.4 million gallons per day in the fourth quarter. Operating expenses should average $0.39 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization. For the fourth quarter, net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $690 million. For 2023, we expect G&A expenses to be approximately $925 million. That concludes our opening remarks.
Before we open the call to questions, please adhere to our protocol of limiting each turn in the Q&A to 2 questions. If you have more than 2 questions, please rejoin the queue as time permits to ensure other callers have time to ask their questions.
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Operator: [Operator Instructions]. Today’s first question is coming from Theresa Chen of Barclays.
Theresa Chen: I’d first like to ask about your outlook for near-term refining margins and specifically on the gasoline side. We’ve seen that significant volatility recently, especially early in October. What do you think explains the recent downside? And how does compare with demand across your footprint? Maybe going back to Lane’s earlier comments on your wholesale system? And just generally, how do you think gasoline margins trend going forward?
Gary Simmons: It’s Gary. Yes, I think you had several factors that contributed to the sharp sell-out on gasoline. You kind of had the market view that hurricane season was over, you were approaching RVP transition. And then the DOE put out some fairly pessimistic demand numbers. And so all that kind of hit at once and caused a fairly significant sell-off in gasoline. In terms of the outlook going forward, we’d expect gasoline to kind of follow typical seasonal patterns, weaker cracks, kind of the fourth quarter and first quarter. The thing we’re really looking at, as you know, the fundamental that looks good to us is the market structure still doesn’t really support storing summer-grade gasoline, putting gasoline in New York Harbor for driving season next year. So as long as that’s the case, our view would be that when you get to driving season next year, demand picks back up, you’ll see cracks respond.
Theresa Chen: Thank you. And on the crude oil side, in terms of light heavy differentials, given the heightened geopolitical risks in the Middle East and coupled with the incremental Venezuelan production following the recent sanctions relief and taking also into account the potential near-term start-up of just focus [ph]. How do you think about the impact of all these variables on light heavy differentials? And how this evolving from here?
Gary Simmons: Yes. So really, the key driver on the light-heavy differentials continues to be the 4.5 million barrels a day that OPEC Plus has off the market. So we saw fairly tight differentials in the third quarter. They have moved wider despite the geopolitical issues that you’ve discussed. Some of that is just typical seasonal patterns. You’ve had less high sulfur fuel burn for power generation in the Middle East. So high sulfur fuel discounts widen some. We’ve seen some turnaround activity, especially in PADD 2 that pushed some heavy seller back on the market as differentials to widen out. Freight markets actually have a fairly significant impact on those differentials as well. So freight moving higher is causing the differentials to move. But we kind of see until the OPEC+ comes back on the market that you’ll have narrower heavy sour differentials and they’ll follow typical seasonal patterns.
Operator: The next question is coming from Sam Margolin of Wolfe Research.
Sam Margolin: This might be one question but in 2 parts, which I know you guys love. So it goes back to the gasoline comment, and it just seems like the market might be more seasonal than it had been in the past just because of the way consumers kind of travel and work. And then — but at the same time, your system has gotten a little more diesel-oriented with the Port Arthur coker and Valero has a history of really strong sort of capture results and execution results in the fourth quarter when there’s typically a lot of volatility and dislocations around all these markets. So the question is do you think that this kind of enhanced seasonality in gasoline is something we should get used to in future years? And in terms of your configuration and position within that, is it arguably better than it was sort of before you brought on some recent projects?
Gary Simmons: Yes. So on the first part of the question in terms of even more seasonality around gasoline, I can’t say that we’re really seeing that. We did see sales throughout our whole system fall off a little bit after Labor Day but they’ve actually recovered quite nicely, and we’re back into that 1 million barrels a day of sales. Gasoline sales year-over-year are up 2% in the current market from where they were last year at this time. Diesel sales are up a little stronger at 8% so I don’t think it really is a seasonability factor that’s impacting gasoline at least in the domestic markets.
Lane Riggs: So to the second part, Sam. It’s — we really had a view since I want to say the 20 — early ’20 teens where we saw the diesel would be sort of the fuel of the future. If is the economic driver. So not only did we do the coker that you alluded to here recently. We also built a 2 big hydro cracker. We revamped the 2 big hydrocrackers, this is all in an effort to make our system more robust and its ability to move around and specifically be able to move towards making more and more distillate out of our assets.
Operator: The next question is coming from Doug Leggate of Bank of America.
Doug Leggate: A couple of questions, if I may. I guess the first one is, I guess, about the Port Arthur Coker and more generally, what you’re seeing going on and got the Gulf Coast as it relates to heavy or advantaged seller crude spreads? And I guess my point is, does Bocas, obviously, Loomis large [ph] in the horizon, but Maya seems to have behaved very differently from your indicator from WCS. And I realize that’s largely your benchmark. So I’m just curious, are we seeing the capture rate from the coker that you anticipated? And what’s your prognosis, I guess, for those advantaged crude spreads that are obviously a big factor in that project?
Lane Riggs: I’m going to hand this off to Gary and Greg, I think, Gary, you might answer the heavy sour part and then Greg wanted to answer this capture rate on the coker.
Gary Simmons: Yes. So we’ve seen heavy sour discounts widen back out. In Canada, they’re back on apportionment on the pipeline. It looks like forecast for fairly robust production in Canada. You’re seeing is welling back on the market. And then our view is, even when this focus does start up, it may take some eye off the market probably increases fuel yield from Mexico. And so that coker, we can use that as a feedstock as well. And I’ll let Greg address the capture question.
Greg Bram: Yes. And Doug, what I’d say about the cokers, it operated very well for the quarter, certainly consistent with our expectations. And so the project is generating good strong economic value, both by lowering feedstock, some of the things Gary is talking about and also enabling us to increase throughput.
Doug Leggate: Sorry, guys, on gas broadcast, is that impacting spreads on the Gulf Coast materially?
Gary Simmons: I don’t think there’s any impact today.
Doug Leggate: Okay. My follow-up is a quick one maybe is for Jason. But another $1.8 billion of buybacks. You’ve now bought back, I think, about 15% of your shares in the last 1.5 years. You still got plenty of cash on the balance sheet, and we know this sector is notoriously seasonal. I’m just curious how we should think about your deployment or strategy of — into seasonal periods when you get — perhaps get more opportunistic?
Jason Fraser: Yes. Thanks, Doug. Yes, it’s okay. I’ll talk about our approach to buybacks is driven by our thoughts around cash, the dividend debt. So I’ll walk you through that and how we’re looking about — thinking about the rest of the year and then we can see — more you won’t be on that. So on cash, as you said, we ended the quarter at $5.8 billion. We’ve indicated mid target of $4 million [ph]. So we’re very comfortable with us being in that current range now. On the debt side, we always practically look at our portfolio through a liability management lens on an ongoing basis, but we certainly don’t have any needs to pay down any debt at this time. Net debt to cap as of September 30 was 17%. So it’s a bit under our target range.
So we’re in good shape there. And on the dividend, we maintain a dividend is competitive, growing and sustainable through the cycle. And we feel like we’re in a reasonable range now. I wouldn’t want to get into more specific on timing or potential dividend increases at this time. And then that brings us to buyback and you know our post to buybacks is to have the annual target of 40% to 50% of adjusted net cash from operations, and we view the buyback as a flywheel supplementing our dividend to hit whatever our target is for the year. In the third quarter, we had a 68% payout year-to-date through the third quarter, we’re at 58%. So I would say, under these conditions, even given the softer seasonality in the fourth quarter, you should definitely expect us to pay out over 50% for the year.
And as you may recall, the pandemic, that was a fairly regular practice of 5 years before the pandemic, I think we averaged like a 57% payout. So in these periods where we have greatly above-average free cash generation, that will probably continue to be our practice.
Doug Leggate: Clarification, Lane, if you don’t mind, the fact you’re already above 50%, the high end of your payout, does that preclude stepping into additional buybacks for the balance of this year?
Jason Fraser: No, no, it does. We look at it on an annual basis, and I would think we’ll be over 50% for the year. So it definitely does…
Operator: The next question is coming from Ryan Todd of Piper Sandler.
Ryan Todd: Maybe could you talk through a little bit about what you’re seeing in renewable diesel markets. 2Q margins were obviously quite soft indicators been weak. Can you talk — was there any impact from hedging losses in the quarter and maybe could you help us if there were kind of a rough estimate of maybe what that was? And then can you just more broadly talk about what you’re seeing in terms of supply demand in the marketplace impact of RIN pricing and RVO limitations, et cetera?
Eric Fisher: Sure, Ryan, this is Eric. I think we saw the RIN prices drop pretty quickly kind of in that September and into October. And really, as you stare at that drop, it was kind of on the news that there was the anticipation of a couple of big start-ups at the end of the year that have now been delayed. It was also in the news that there was going to be with Russia freezing out its exports that it would force the U.S. to export more, therefore, drop the obligation. So the combination of all that news kind of caused a precipitous drop in the RINs kind of right at the end of the quarter and into the beginning of the fourth quarter. The real margin loss there is really because as fat prices have since adjusted in the spa [ph] market but obviously, there’s a lag of our fat prices that kind of carried on that have since started to catch up with this drop in credit prices.
But we’ll see that continue to carry through, through the fourth quarter. But overall, I think that’s really what we’re seeing. The spot margin is cleaned back up. Fat prices continue to come off. You really see all of that being kind of a return to profitability here in the fourth quarter. So that’s really what we see going on in the RD market.
Ryan Todd: Okay. And then maybe switching on the refining side, as we think about PADD 5, it was really quite strong through third quarter on a relative basis across the country and into the early part of the fourth quarter. Can you talk maybe about what you’re seeing overall in terms of kind of supply/demand in PADD 5 across your operations there? There’s a lot of moving pieces with some refineries that are — that have transitioned off the market from conversions right now. So how do you — as you look forward on the next — do you expect that market to stay relatively tight for the foreseeable future? And how do you think about it relative to your operations there?
Gary Simmons: Ryan, this is Gary. I think our view of PADD 5 is that with the renewable diesel coming into the market, the market should be well supplied on the distillate side but it’s going to be very tight on gasoline. You just don’t have the gasoline production that you used to have with the refinery conversions. And so when one refinery goes down, it’s going to create a lot of shortness in the market.
Operator: The next question is coming from Manav Gupta of UBS.
Manav Gupta: Guys, you are known for your capital discipline and you look at a lot of projects and in the end, very few actually make it through the funnel. We are somewhere in October. You guys haven’t talked about a major project yet. And I’m just wondering if 2024 would then be more of a quick hit projects. I mean, coker has already come online. So when I look at 2024, should we think for the year where you could be doing more quick hit projects versus a mega project, which generally can go on for 3 to 4 years?
Lane Riggs: This is Lane. So the way I would — I agree with you, and that’s — we still believe we can — we’ll spend somewhere between $0.5 billion to $1 billion a year of strategic capital. But when you look at sort of what’s the nature of those, certainly on the refining side, they are going to be shorter cash cycle types of projects instead of a big like a coker type project there’ll be a series of small projects. And then when you further drill down and what do we look for? We look for refining projects to lower our cost to produce. We also like projects and improve our reliability and then, of course, we like to hold renewable line in terms of its ability for us to drop the carbon intensity of our fuels. And as you also said, we’re very careful about our communication on projects. We’d like to be a little closer to FID or at FID before we really talk about them.
Manav Gupta: Perfect. Just a quick follow-up. We have seen some sanction relief on the Venezuelan side. You were buying from Chevron even before that and Chevron had been giving the indications that they could ramp up over there. So can you help us understand like what kind of volume — incremental volumes could come to the market from the Venezuelan side in probably next 2 or 3 years?
Gary Simmons: Yes, this is Gary. So if you look, there’s about 250,000 barrels a day of exports in Venezuela, most of that volume is going to the Far East. But with the lifting of sanctions, it has the potential to make its way to the U.S. Gulf Coast.
Operator: The next question is coming from John Royall of JPMorgan.
John Royall: So we’ve talked about coastal light heavy dips and how they’ve tightened up pretty significantly. Can you remind us how much flexibility you have in your system to run lights versus heavies versus mediums?
Greg Bram: John, this is Greg. So we can flex quite a bit. What you’ll tend to see us do is when the medium grades look attractive, we’ll ramp that up and kind of back down to both the lights and the heavies conversely, when heavy sours get more attractive relative to the medium grades will ramp up the heavies. I don’t remember the exact percentages. We can get those to you. I think they might actually be in our — in IR deck yet. Page 30 there. But that tends to be what drives us to kind of swing between those different grades.
John Royall: Great. And then maybe you can talk about the beat and utilizations in 3Q. You didn’t call out anything in particular, but you’re above the high end and I think every region, but one. It seems like the system ran quite well. Are there any moving pieces to call out maybe maintenance getting pushed out or anything of that sort or is it just better-than-expected operations?
Lane Riggs: I would say we didn’t — the third quarter is always going to be a period where you don’t have a lot of turn on activity. I mean some of it might leak over from the second or you might start a little bit going into the fourth. But system industry-wide, we’re not unique in that sense. Most of your turnaround work is either done in the first and second or the fourth quarter. And so it should be a high utilization. And obviously, we’ve emphasized reliability got for the last, I don’t know, more than a decade, we have the programs that we have. So you would expect us when we’re not having turnarounds to have a pretty high level of utilization of our assets.
Operator: The next question is coming from Joe Laetsch of Morgan Stanley.
Joe Laetsch: So, I wanted to start on the diesel side. So you talked about gasoline cracks, but we hit so much [ph] which just remains really strong here. So I was just curious what your thoughts on the setup for diesel here into the winter. We have low inventories in both the U.S. and Europe and last year, we kind of had a similar level of tightness and were bailed out by a warmer winter. So just curious on your thoughts on the setup for diesel margins.
Gary Simmons: Yes. So diesel demand remains very strong. I guess I mentioned diesel sales in our system are up about 8% year-over-year. Our view of the broader markets is that diesel demand in the U.S. is probably down about 1% year-to-date from where it was last year, and that’s mainly due to the warmer winter we had last year. Our guys’ estimate, we lost about 125,000 barrels a day of diesel demand due to the warmer weather. So inventories remain below the 5-year average level, demand remains good. So you’re heading into winter with low inventories, and we would expect strong diesel cracks through the winter and could get very strong if we have a colder winter.
Joe Laetsch: And then shifting gears a little bit. So you’ve talked a little bit about RD margins being pressured here. So I was just hoping you could touch on some of the regional dynamics that you’re seeing and economics of selling into other states in the Coast or potentially Canada to offset in the lower LCFS prices that we’ve seen in California?
Lane Riggs: Yes, we absolutely see. California has become kind of the ore of the RD market. We see more opportunity in Oregon, Washington and Canada as kind of the growth opportunities. And so we absolutely look to maximize our product sales into those markets. California continues to talk about the obligation for 2030. They sort of pushed off a lot of their — they’re still doing a lot of their conferences and workshops on that. We still fully expect that at some point, they are going to announce the changes to be effective sometime next year, and that will increase the LCFS price in California. So — but in the meantime, we continue to look at — again, you kind of mentioned that. We still have the advantages being on the Gulf Coast.
Do you have access to all of the global feedstocks. You have access to all the global markets so it gives us a lot of capability to go to different markets. And we continue to see waste oils advantaged versus vegetable oils from a CI standpoint. So you look at that low-cost producer on the Gulf Coast, that just continues to be kind of the winning formula for being able to have flexibility to go to different markets in the RD space [ph].
Operator: The next question is coming from Neil Mehta of Goldman Sachs.
Neil Mehta: Lane, first question is for you is just — it’s been a couple of months since you stepped to the job as CEO. Just would love your perspective on early observations, recognizing the strategy has been very consistent and steady for a long time, and you’ve been a big part of it. But early observations as the new leader of the organization and key strategic priorities that we haven’t really talked about here on the call thus far.
Lane Riggs: It’s been a couple of years, Neil. I’m just — but it’s been great. You always got to remember, I was an integral part of really Joe’s team really from the beginning of his [indiscernible] you’ve mentioned, it’s been a very successful one. So are there things that I’m trying to do maybe a little bit differently, I’d say I put my thumb on the scale for issues maybe a little bit and maybe unweighted others. But largely speaking, our strategy is the same because it was successful and it’s currently successful. I don’t know that I have any real plans to deviate from that. Obviously, the world can change and we respond accordingly. But the world looks at least — this business looks a whole life like it did a year ago. So our outlook is pretty much unchanged.
Neil Mehta: Now that’s — we definitely see the consistency. The second question is — it’s a very — it’s a smaller part of your business, but it’s always — you can create volatility in earnings is ethanol. Just you’re curious on your outlook for that business and — what — how far away are we from mid-cycle as you think about it?
Lane Riggs: Yes. The ethanol obviously has had a good year this year with lower corn prices and low natural gas prices. So the ethanol margins have been, I would say, higher than what we would call a mid-cycle but it’s not really exceptionally higher than mid-cycle. It’s actually been fairly strong. But I would say, looking back historically, ethanol is always kind of a steady drumbeat business. We do see that the biggest opportunity here is still this low-carbon opportunity and some of the growth in other markets in the world. Again, we are 30% of the export capability of ethanol for the U.S. And so we see this interest in the world, lowering its carbon footprint by increasing its ethanol blending. So Canada, has become an E10 country almost overnight.
There’s talk about that going to E15 next year. We’re seeing other countries that are starting to look at incremental ethanol blending. And then there’s a lot of interest in ethanol as a feedstock into chemicals and solvents and paints. And so I think we still see a lot of good opportunities for ethanol globally that I think will keep us in a very strong margin environment. And then obviously, I mean, so much of that depends on weather, ultimately. I mean, obviously, no one can control that. But the U.S. is a big ag country. We have a lot of capability to grow a lot of corn. And so as long as that holds up, then I think ethanol has got a good outlook.
Operator: The next question is coming from Paul Cheng of Scotiabank.
Paul Cheng: Two, hopefully, the quick question. First, maybe either is for Lane or Gary. Look like at branding economic why now is really good. With the wind — if we’re looking at your system, what is the incremental percentage of the gasoline supply will increase as a result of those branding for you versus less quarter third quarter the level over the fourth quarter last year, whatever is the comparison you want to use? And secondly, that I want to see what is — if you can you give us any color that how’s the turnaround cycle look like for you next year and whether that compared to this year, going to be about the same, lighter, heavier also? And also that whether you think the industry is going to have a normal cycle next year after the catch up this year or that the catch-up is going to continue into next year?
Gary Simmons: So if I understand correctly, the first was how much really does the gasoline pool well as you go to higher RVP gasoline. Is that what you were asking, Paul?
Paul Cheng: Yes. I mean that every year that when we go to the wind grade, obviously, you see more branding, but that with the economics of light is actually very active for the branding. And I assume that given the winter grade, it will also allow you to have more flexibility than your brand the strict late into the system and it looks like it’s very economic also.
Greg Bram: Yes, Paul, this is Greg. So you’re right. You definitely increase the amount of primarily butane that you blend into the gasoline. It ranges depending on which region ring and the change in specs, it’s in the 5% to 10% range. And then you’re right that to the extent that butane has a higher octane than the pool, it does allow you to put more of the lower octane component into the blend [indiscernible] one of those right now that looks pretty attractive.
Paul Cheng: Sorry. Please go ahead.
Lane Riggs: No, I was just going to answer you — I think it was your same question around turnarounds. We sort of have a policy for a while that we don’t give any real outlook on our turnaround or the industry turnaround behavior. So.
Paul Cheng: And if I can just go back into the earlier question about — great answer. Any kind of, say, because that when it is more economic, it tends to brand more, but on the other hand, gasoline is not great right now. So I’m trying to understand that how the 2 years going to be impacting in your thinking or your accident here.
Lane Riggs: I think — if I understand, Paul, back to winter blending. Obviously, [indiscernible], butane is relatively cheap. And we always look at economic signals to try to determine how much gasoline are produced and that compares to sort of the reformulated grade, they might require less butane. And then there are specs that you hit, I mean you would think you would get near 10% in butane in full, but a lot of times we hit other specifications and the finished gasoline besides RVP. And so I mean, it’s a fair.
Operator: The next question is coming from Jason Gabelman of TD Cowen.
Jason Gabelman: I wanted to first go back to uses of cash or returns of cash, I should say. And I know Valero has a 40% to 50% payout ratio. It seems like you’re returning a majority of the excess cash post dividends via buyback, maybe 2/3 of that excess cash. Is that kind of how we should think about return of cash moving forward essentially all of the excess cash or the majority of it beyond what you pay out in the dividend is going to be going towards the buyback for the foreseeable future. And I think some color around that could help the market bring some of that potential future buyback value forward? And I have a follow-up.
Lane Riggs: Jason, this is Lane. Look — directionally correct, but we still have to — some of our cash obviously goes to sustaining our asset. So that’s something that we’re committed to. So we want to make sure that we’re, a, that we are — we had the earnings potential, our assets stay in a posture that we can always generate the right earnings with the market conditions and second, we maintain the dividend. And then we do believe we still have this sort of $0.5 billion to $1 billion of strategic capital in all that’s done, all the excess cash will go to buybacks.
Jason Gabelman: All right, great. And my second one is kind of on the strategic growth outlook. We’ve seen some of your larger peers use equity to buy up comped recently? And if I think about some of the potential areas you could expand into like chems, like low carbon fuels, those valuations have come down relative to where Valero trades. I don’t know Valero doesn’t typically use the equity to acquire other companies. But given what’s going on with Navigator Pipeline and looking at your potential future growth opportunities, are you taking a closer look at strategic M&A and using equity given your stock and refiners in general have held up pretty well relative to other potential step-out opportunities?
Lane Riggs: This is Lane again. I would say that we look at all these opportunities and all the business lines that I alluded earlier. And we have an entire group, our innovation group that’s constantly looking at how can we bolt on and leverage our existing footprint, which, obviously, we have a big footprint in ethanol, we have a pretty big footprint renewable diesel. And we’re also looking at everything else. Everything is on the table. We’re always looking at it, but we are also very careful in terms of how we talk about it and how we’re going to announce things. In terms of how we finance it, it’s just a matter of when we — as the world evolves, we’ll come up with the best way that we think to finance something. But obviously, all these things have to go through sort of our investment gated process.
Operator: The next question is coming from Roger Read of Wells Fargo.
Roger Read: Yes. Maybe to follow up on Mr. Gabelman’s question there. If we think about acquisitions, latest news says CITGO is potentially going to be on the [indiscernible] beginning of next year. So just curious how you think about greater footprint within refining as any kind of a possibility.
Lane Riggs: So Roger, this is Lane. So as you know our history, we were a big consolidator in the industry going back to 2000. That to really our last major acquisition was sort of circa 2013. That’s when our base became somewhat like it looks today. So we understand probably as well as any operator out there would it take to buy something or to merge something and get it on our system and all the costs associated with it. And we always get everything that we think within reason. I mean we always analyze everything and — we haven’t bought anything like I said, since 2013 on any refining assets. You never say never. We look at everything, and we’ll again, like I alluded to on Jason’s question, we’ll run it through our processes and figure out where there anything that makes sense for us or not.
Roger Read: Yes. I’d imagine the data.
Lane Riggs: Clear on that, Roger. They got to compete with everything else, including buyback, right? So.
Roger Read: Right, right. No. I mean the data room is going to have to be interesting at a minimum. Second question I have, it’s unrelated, but kind of a follow-up on some of the things going on the renewable fuel side. We’ve seen a lot of downward moves or we saw a strong downward move, I should say, in the D4, D6 RINs kind of latter part of Q3 and the early part of Q4. It looks like the market is more or less sort of adjusting to that on some of the feedstock and other issues. But I was just curious if you all have any read-throughs on what cause that decline and whether or not this decline sort of reflects current situation? Or is there more downside risk to RINs given the mandate versus production numbers and obviously an increasing volume of renewable diesel coming in ’24 from the industry?
Lane Riggs: Yes. I think as I mentioned before, there’s this kind of constant talk about oncoming production, increased rates, Arthurs [ph] projects that has always said at some point the D4 is going to be under pressure especially since the EPA did not raise the D4 obligation in their last set rule. So I think though, is — and then we combine that with there is this kind of a rush, I think, look like to me kind of a rush to sell RINs in the third quarter with that narrative, combined with that Russian announcement that they were going to ban exports, which kind of quickly evaporated. So there’s, I think, a kind of a more of a temporary view that the D4 [ph] was going to drop even more. And like you’ve observed, it’s kind of recovered and fat prices have also since adjusted.
We could see that biodiesel and veg oil RD is negative now. That’s one of the things we’ve always said is that the lower CI waste oil play was always going to be more advantageous. So even at these lower credit values, we’re still the advantage platform. So as you go into 2024, obviously, obligations already set. It’s hard to tell exactly where that’s going to go. There’s no doubt that R&D will continue to grow. We do see that for us, you’re going to see R&D continue to grow, as we talked before, Canada is a big outlet, which takes a lot of this RIN exposure away and then you also obviously have the SAP project come on, where we’ll diversify into a different market. And so — and then and if for some reason, SAP doesn’t work, that product also meets Arctic diesel grades that again, go to Nordic countries and Canada.
So there’s no doubt that there’s going to be a continued pressure on the RINs for both the D4 and D6 but our strategy has always been — there’s other markets that you can minimize the impact of that. And then with our platform, we’re still the most advantaged from a cost and CI standpoint.
Roger Read: I appreciate that coastal advantage as always.
Operator: Our last question for today is coming from Matthew Blair of Tudor, Pickering, Holt.
Matthew Blair: Circling back to the R&D margins in Q3, are you able to quantify the impact from DGD to fire on the reported $0.65 gallon EBITDA margin?
Lane Riggs: No, we usually don’t give that kind of detail. I would say it wasn’t large, just [indiscernible] at that.
Matthew Blair: Sounds good. And then on the refining side, could you talk about your product exports in Q3 and so far into Q4? And do you expect any negative impact from this announcement from Mexico a couple of days that you’re looking to restrict refined product imports into the country?
Gary Simmons: Yes, I’ll take the first part of it and then let Rich Walsh handle the second part. Yes, our exports, if you look at the exports in the third quarter, we did 389,000 barrels a day, 281 a distillate, 108 of gasoline. Based on second quarter, the volumes are up based on historic numbers, they trended up as well to our typical export locations. Most of the line went to Latin America, about 70% of the diesel in Latin America and about 30% to Europe. And those are remaining at those levels as we move into the fourth quarter.
Richard Walsh: This is Rich. I’ll just answer the second half of it. On this decree an issue, it’s actually rightly aimed at import smuggling that’s going on. So you have individuals that are trying to bring product gasoline diesel into Mexico, but describing it as something that has a lower tariff like a tariff, something like that and importing it in. And that’s resulting in them getting a lower tariff. So this decree is really focused in on that. For Valero, we’re properly importing all of our gasoline and products, and we’re paying the full and proper tariff for it. So — and then also all of our fuel comes out of our own system, and it’s all high-quality meet suspect [ph]. So we have a lot of interaction with the Mexican authorities. They’re aware of the legitimacy of our operation. And so we don’t expect this initiative to be an issue for us.
Operator: Thank you. At this time, I’d like to turn the floor back over to Mr. Bhullar for closing comments.
Homer Bhullar: Thanks, Donna. I appreciate everyone joining us today. And as always, if you have any further questions, please feel free to contact the IR team on the call. Thanks again, and everyone have a great day.
Operator: Ladies and gentlemen, thank you for your participation. This concludes today’s event. You may disconnect your lines or log off the webcast at this time, and enjoy the rest of your day.