Valero Energy Corp (VLO) — Q3 2023 Earnings Call Transcript

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. 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.

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 project at Port Arthur remains on schedule and is expected to be complete in 2025. Once complete, we expect the Arthur plant to have the optionality to upgrade up to 50% of its current 470 million-gallon annual renewable diesel production capacity at DGD. 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 sustainable aviation fuel 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 in the 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.

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 margins 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 member 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. The 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 canceled 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 sustainable aviation fuel 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 modeling 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 non-cash 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 non-cash 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.

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 it 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?

It's Gary. Yes, I think you had several factors that contributed to the sharp sell-out on gasoline. You 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 in 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 the driving season next year. So as long as that's the case, our view would be that when you get to the driving season next year, demand picks back up, and you'll see cracks respond.

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 into account the potential near-term start-up of just focus, how do you think about the impact of all these variables on light-heavy differentials? And how this is evolving from here?

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 have widened some. We've seen some turnaround activity, especially in PADD 2 that pushed some heavy seller back on the market as differentials widened 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 OPEC+ comes back on the market that you'll have narrower heavy sour differentials, and they'll follow typical seasonal patterns.

This may be one question but in two parts, which I know you appreciate. It relates back to the gasoline comment, and it seems that the market may have become more seasonal than in the past due to changes in consumer travel and work patterns. At the same time, your system has become more diesel-oriented with the Port Arthur coker, and Valero has a track record of strong capture and execution results in the fourth quarter, which usually sees a lot of market volatility and dislocations. So the question is whether you believe this increased seasonality in gasoline is something we should expect to continue in the upcoming years. Also, considering your configuration and position now, do you think it is arguably better than it was before the recent projects were implemented?

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.

So to the second part, Sam. We've really had a view since I want to say the early 2010s where we saw diesel would be sort of the fuel of the future, if it's the economic driver. So not only did we do the coker that you alluded to here recently, but we also built two big hydrocrackers and revamped those to improve our system's robustness and ability to move towards making more distillate out of our assets.

A couple of questions, if I may. I guess the first one is about the Port Arthur coker and more generally, what you're seeing going on in the Gulf Coast as it relates to heavy or advantaged seller crude spreads? And I guess my point is, does Bocas have a large presence 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?

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 the capture rate on the coker.

Yes. We've seen heavy sour discounts widen back out. In Canada, they're back on apportionment on the pipeline. It looks like the forecast for fairly robust production in Canada is coming back on the market. And then our view is, even when this focus does start up, it may take some time off the market, but probably increases fuel yield from Mexico. And so that coker, we can use that as a feedstock as well. I'll let Greg address the capture question.

Yes. And Doug, what I'd say about the cokers is that it operated very well for the quarter, certainly consistent with our expectations. The project is generating good strong economic value, both by lowering feedstock costs, some of the things Gary is talking about, and also enabling us to increase throughput.

Sorry, guys, on gas broadcast, is that impacting spreads on the Gulf Coast materially?

I don't think there's any impact today.

Okay. My follow-up is a quick one maybe 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 more opportunistic?

Thank you, Doug. I appreciate the opportunity to discuss our approach to buybacks, which is influenced by our strategies regarding cash, dividends, and debt. I'll outline our position and how we plan to navigate the rest of the year. As mentioned, we finished the quarter with $5.8 billion in cash, and our mid-term target is around $4 billion, so we are comfortable maintaining our current position. We continuously assess our portfolio through a liability management lens and currently do not have any debt repayment needs. As of September 30, our net debt to capitalization was 17%, which is slightly below our target range, positioning us well. Regarding the dividend, we offer a competitive, growing, and sustainable dividend throughout the cycle, and we believe we are within a reasonable range at this point. I won't delve into specifics on timing or potential increases just yet. Now, regarding buybacks, our annual target is to allocate 40% to 50% of adjusted net cash from operations towards this effort. We view share repurchases as a complement to our dividend strategy to meet our yearly targets. In the third quarter, our payout ratio was 68%, and year-to-date we stand at 58%. Given the current conditions and expected softer seasonality in the fourth quarter, we anticipate a payout of over 50% for the entire year. To recall, during the pandemic, our average payout over the five years prior was about 57%. In times of significantly higher free cash generation, we plan to continue this practice.

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?

No, no, it does not. We look at it on an annual basis, and I would think we'll be over 50% for the year. So it definitely does not...

Could you provide some insights into the current state of the renewable diesel markets? The margins in the second quarter were notably low and the indicators have not been promising. Was there any impact from hedging losses during the quarter? If possible, could you give us a rough estimate of what that might be? Additionally, could you discuss the broader trends in supply and demand, as well as the effects of RIN pricing and RVO limitations in the marketplace?

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 startups 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, dropping 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 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. Overall, I think that's really what we're seeing. The spot margin has 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 renewable diesel market.

Okay. And then maybe switching on the refining side, as we think about PADD 5, it was really quite strong through the 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 supply and demand in PADD 5 across your operations there? There's a lot of moving pieces with some refineries that have transitioned off the market from conversions right now. So how 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?

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. When one refinery goes down, it's going to create a lot of shortness in the market.

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. I'm just wondering if 2024 would then be more of quick-hit projects. I mean, the 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?

This is Lane. I agree with you, and we still believe we can invest between $0.5 billion to $1 billion annually in strategic capital. In terms of refining, we are focusing on shorter cash cycle projects rather than large-scale projects like a coker. Our strategy will involve a series of smaller projects. Specifically, we look for refining initiatives that reduce our production costs, enhance our reliability, and allow us to reduce the carbon intensity of our fuels through renewable options. As I mentioned earlier, we are cautious about discussing projects until we are closer to a Final Investment Decision or at that stage.

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 what kind of volume incremental volumes could come to the market from the Venezuelan side in probably the next two or three years?

Yes, this is Gary. 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. With the lifting of sanctions, it has the potential to make its way to the U.S. Gulf Coast.

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?

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 on both the lights and the heavies. Conversely, when heavy sours get more attractive relative to the medium grades, we 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 IR deck. But that tends to be what drives us to swing between those different grades.

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 in, 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?

I would say the third quarter is typically a time when we don't see a lot of turn-on activity. Some projects might carry over from the second quarter, or we might begin some work as we head into the fourth quarter. Industry-wide, we are not an exception to this trend. Most turnaround activities are completed in the first and second quarters or during the fourth quarter, so we expect high utilization during this time. For over a decade, we have focused on reliability through our existing programs. Therefore, when we are not engaged in turnarounds, we would anticipate a strong level of utilization of our assets.

So, I wanted to start on the diesel side. You talked about gasoline cracks, but we hit this other point, which just remains really strong here. 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.

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. Inventories remain below the 5-year average level, and demand remains good, so you're heading into winter with low inventories. We would expect strong diesel cracks through the winter and could get very strong if we have a colder winter.

And then shifting gears a little bit. So you've talked a little about renewable diesel margins being pressured here. 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 the lower LCFS prices that we've seen in California?

Yes, we see California as a central hub for the renewable diesel market. There are significant growth opportunities in Oregon, Washington, and Canada, and we intend to maximize our product sales in those areas. California is still discussing its 2030 obligations and is continuing with various conferences and workshops. We expect them to announce changes that will likely take effect next year, which should increase the LCFS price in California. In the meantime, we benefit from our location on the Gulf Coast, which provides access to global feedstocks and markets, giving us the flexibility to enter different markets. We also recognize that waste oils are more favorable than vegetable oils in terms of carbon intensity. Being a low-cost producer on the Gulf Coast remains a successful strategy for maintaining the flexibility to operate across various markets in the renewable diesel sector.

Lane, could you share your thoughts on your early observations since taking on the CEO role a couple of months ago? While the strategy has remained consistent and you've been integral to it, what key strategic priorities have emerged that we haven't discussed during this call?

It’s been a couple of years, Neil. It's been great. You always have to remember that I was a key part of Joe's team from the start of his leadership. As you noted, it has been very successful. Am I trying to do things a bit differently? I have focused on some issues more than others. However, our strategy remains largely the same because it has been successful and continues to be successful. I don't have any concrete plans to change that. Of course, the world can change and we will respond as needed. But this business looks very similar to how it did a year ago, so our outlook remains pretty much unchanged.

Now we definitely see the consistency. The second question is about a smaller part of your business, which can create volatility in earnings, that is ethanol. I am curious about your outlook for that business and how far away you think we are from mid-cycle.

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. Looking back historically, I would say 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. There is interest in lowering the carbon footprint by increasing ethanol blending. 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, solvents, and paints. I think we still see a lot of good opportunities for ethanol globally that will keep us in a very strong margin environment. Much of that depends on weather, ultimately. Obviously, no one can control that. But the U.S. is a big agriculture country. We have a lot of capability to grow a lot of corn. As long as that holds up, then I think ethanol has a good outlook.

I have two quick questions. First, this is for either Lane or Gary. It seems that the branding economics are favorable right now. Looking at your system, what is the expected percentage increase in gasoline supply due to these branding efforts compared to the third quarter of last year and the fourth quarter? You can use whatever comparison you think is best.

So if I understand correctly, the first was how much does the gasoline pool well as you go to higher RVP gasoline. Is that what you were asking, Paul?

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 and the change in specs, it's in the 5% to 10% range. And 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; that's one of those right now that looks pretty attractive.

Sorry. Please go ahead.

No, I was just going to answer you. I think it was your same question about turnarounds. We have a policy that we don't provide any real outlook on our turnaround or the industry's turnaround behavior.

I wanted to first go back to the 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 two-thirds 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. 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.

Jason, this is Lane. We are directionally correct, but we still need to allocate some of our cash to sustain our asset, which we are committed to. We want to ensure that we maintain the dividend. We still have approximately $0.5 billion to $1 billion available for strategic capital, and any excess cash will be used for buybacks.

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 companies recently? And if I think about some of the potential areas you could expand into like chemicals, like low carbon fuels, those valuations have come down relative to where Valero trades. I know Valero doesn't typically use 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?

This is Lane again. We are exploring various opportunities across all our business lines that I mentioned earlier. Our innovation team is consistently assessing how we can expand and utilize our existing operations, particularly in ethanol and renewable diesel, both of which we have a significant presence in. We are considering all options and are always on the lookout, but we approach discussions and announcements carefully. Regarding financing, it will depend on the evolving landscape, and we will determine the best financing strategies as needed. However, all these initiatives must align with our investment gated process.

Yes. Maybe to follow up on Mr. Gabelman's question there. If we think about acquisitions, the latest news says CITGO is potentially going to be on the market beginning of next year. Just curious how you think about greater footprint within refining as any kind of a possibility.

So Roger, this is Lane. Our history shows we were a significant consolidator in the industry going back to 2000. Our last major acquisition was around 2013, which is when our base started to resemble what it looks like today. We understand as well as any operator what it takes to buy or merge and integrate something into our system, along with the associated costs. We always analyze everything, and we haven't acquired any refining assets since 2013. However, we remain open to possibilities. We evaluate all opportunities, and as I mentioned in response to Jason's question, we will follow our processes to determine if there is anything that makes sense for us.

Yes. I'd imagine the data.

Clear on that, Roger. They got to compete with everything else, including buyback.

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 in 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 caused that decline and whether or not this decline reflects the 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?

Yes. I think as I mentioned before, there's this constant talk about upcoming production, increased rates, projects that have 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. I think though, and then we combine that with there was a 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 quickly evaporated. So there's a more of a temporary view that the D4 was going to drop even more. Like you've observed, it's recovered, and fat prices have since adjusted. We could see that biodiesel and vegetable oil renewable diesel is negative now. That's one of the things we've always said is the lower carbon intensity waste oil play was always going to be more advantageous. So even at these lower credit values, we're still the most advantaged from a cost and carbon intensity standpoint. As you go into 2024, obviously, obligations are already set. It's hard to tell exactly where that's going to go. There's no doubt that renewable diesel will continue to grow. We do see that for us, you're going to see renewable diesel continue to grow. Canada is a big outlet, which takes a lot of this RIN exposure away and you also obviously have the SAP project come on, where we'll diversify into a different market. If for some reason SAP doesn't work, that product also meets Arctic diesel grades that again go to Nordic countries and Canada. No doubt that there's going to be continued pressure on the RINs for both D4 and D6, but our strategy has always been that there are other markets that you can minimize the impact of that. With our platform, we're still the most advantaged from a cost and carbon intensity standpoint.

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?

No, we usually don't give that kind of detail. I would say it wasn't large, just for context.

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?

Yes, I'll take the first part of it. 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 the second quarter, the volumes are up based on historic numbers, they trended up 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. Those are remaining at those levels as we move into the fourth quarter.

This is Rich. I'll just answer the second half of it. On this decree and issue, it's actually rightly aimed at import smuggling that's going on. You have individuals trying to bring product gasoline diesel into Mexico while describing it as something that has a lower tariff. The decree is really focused 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. All of our fuel comes out of our own system, and it's all high-quality meet specs. We have a lot of interaction with the Mexican authorities. They're aware of the legitimacy of our operation. So we don't expect this initiative to be an issue for us.

Thanks, Donna. I appreciate everyone joining us today. 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.