Greetings, and welcome to Valero's Second Quarter 2022 Earnings Conference Call. At this time, all participants are on a listen-only mode. A question-and-answer session will follow the formal presentation. If you would like to ask a question, you may press star one on your telephone keypad. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Homer Bhullar, Vice President, Investor Relations. Thank you. Please go ahead. Good morning, everyone, and welcome to Valero Energy Corporation's Second 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 Vice President and Chief Commercial Officer, and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at investorvalero.com. Also, attached to the earnings release are tables that provide additional financial information on our business segments 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 expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now I'll turn the call over to Joe for opening remarks. Thanks, Homer, and good morning, everyone. I'm pleased to report that our team maximized refining run rates in the second quarter while executing our long-standing commitment to safe, reliable, and environmentally responsible operations. In fact, we've been increasing throughput since 2020 as demand recovered along with the easing of COVID-19 pandemic restrictions. Our refinery utilization rate increased from the pandemic low of 74% in the second quarter of 2020 to 94% in the second quarter of 2022. Refining margins in the second quarter were supported by continued strength in product demand, coupled with low product inventories and continued energy cost advantage for U.S. refineries compared to global competitors. Product supply is constrained as a result of significant refinery capacity rationalization that was triggered by the COVID-19 pandemic, driving the shutdown of marginal refineries and conversion of several refineries to produce low- carbon fuels. In addition, the Russia-Ukraine conflict intensified the supply tightness with less Russian products in the global market. However, product demand has been strong due to the summer driving season and pent-up demand for travel. Valero continues to maximize refinery throughput to help supply the market at this time when global product inventories are at historically low levels. Our low-carbon renewable diesel and ethanol segments also performed well in the quarter. The renewable diesel segment had record production volumes as the DGD expansion, DGD 2, ramped up to full capacity. On the strategic front, we remain on track with our growth projects that reduce cost and improve margin capture. The Port Arthur Coker Project, which is expected to increase the refinery's throughput capacity while also improving turnaround efficiency, is expected to be completed in the first half of 2023. As for low-carbon projects, the DGD 3 renewable diesel project located next to our Port Arthur refinery is expected to be operational in the fourth quarter of 2022. The completion of this 470 million gallon per year plant is expected to nearly double DGD's total annual capacity to approximately 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha. BlackRock and Navigator CO2 Ventures' carbon sequestration project is progressing on schedule and is expected to begin startup activities in late 2024. We are expected to be the anchor shipper with eight of our ethanol plants connected to this system, which should provide a lower carbon intensity ethanol product and generate 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. 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 incurred $4 billion of incremental debt in 2020 during the low margin environment resulting from the pandemic. Since then, we've reduced our debt by $2.3 billion, including a $300 million reduction in June. We'll evaluate further deleveraging opportunities going forward. In summary, we remain focused on safe, reliable, and environmentally responsible operations and on maximizing system throughput to provide the essential products that the world needs. We continue to strengthen our long-term competitive advantage through refining optimization projects and to grow our business through innovative low-carbon fuels that enhance the margin capability of our portfolio. With that, Homer, I'll hand the call back to you. Thanks, Joe. For the second quarter of 2022, net income attributable to Valero stockholders was $4.7 billion or $11.57 per share, compared to $162 million or $0.39 per share for the second quarter of 2021. Adjusted net income attributable to Valero stockholders was $4.6 billion or $11.36 per share for the second quarter of 2022, compared to $260 million or $0.63 per share for the second quarter of 2021. For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables. The refining segment reported $6.2 billion of operating income for the second quarter of 2022, compared to $349 million for the second quarter of 2021. Adjusted operating income was $6.1 billion for the second quarter of 2022, compared to $442 million for the second quarter of 2021. Refining throughput volumes in the second quarter of 2022 averaged 3 million barrels per day, which was 127,000 barrels per day higher than the second quarter of 2021. Throughput capacity utilization was 94% in the second quarter of 2022, compared to 90% in the second quarter of 2021. Refining cash operating expenses of $5.20 per barrel in the second quarter of 2022 were $1.07 per barrel higher than the second quarter of 2021, primarily attributed to higher natural gas prices. Renewable diesel segment operating income was $152 million for the second quarter of 2022, compared to $248 million for the second quarter of 2021. Renewable diesel sales volumes averaged 2.2 million gallons per day in the second quarter of 2022, which was 1.3 million gallons per day higher than the second quarter of 2021. The higher sales volumes were attributed to DGD 2's operations, which started up in the fourth quarter of 2021. The ethanol segment reported $101 million of operating income for the second quarter of 2022, compared to $99 million for the second quarter of 2021. Adjusted operating income, which primarily excludes the gain from the sale of our Jefferson ethanol plant, whose operations were idled in 2020, was $79 million for the second quarter of 2022. Ethanol production volumes averaged 3.9 million gallons per day in the second quarter of 2022. For the second quarter of 2022, G&A expenses were $233 million, and net interest expense was $142 million. Depreciation and amortization expense was $602 million, and income tax expense was $1.3 billion for the second quarter of 2022. The effective tax rate was 22%. Net cash provided by operating activities was $5.8 billion in the second quarter of 2022. Excluding the favorable impact from the change in working capital of $594 million and the other joint venture members' 50% share of DGD's net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $5.2 billion. With regard to investing activities, we made $653 million of capital investments in the second quarter of 2022, of which $298 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $355 million was for growing the business. Excluding capital investments attributable to the other joint venture members' 50% share of DGD and those related to other variable interest entities, capital investments attributable to Valero were $524 million in the second quarter of 2022. Moving to financing activities, earlier this month, our Board of Directors approved a regular quarterly common stock dividend of $0.98 per share, payable on September 1 to holders of record on August 4. We returned 42% of adjusted net cash provided by operating activities to our stockholders through dividends and stock buybacks in the quarter, which is at the low end of our annual 40%-50% target payout ratio. With respect to our balance sheet, we completed another debt reduction transaction in the second quarter that reduced Valero's debt by $300 million. As Joe already noted, this transaction, combined with the debt reduction and refinancing transactions completed in the second half of 2021 and the first quarter of 2022, have collectively reduced Valero's debt by $2.3 billion. We ended the quarter with $10.9 billion of total debt, $2 billion of finance lease obligations, and $5.4 billion of cash and cash equivalents. The debt-to-capitalization ratio, net of cash and cash equivalents, was 25%, down from the pandemic high of 40% at the end of March 2021, which was largely the result of the debt incurred during the height of the COVID-19 pandemic. We ended the quarter well-capitalized with $4.6 billion of available liquidity excluding cash. Turning to guidance, we 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 fuels businesses. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges. Gulf Coast at 1.72-1.77 million barrels per day. Mid-Continent at 420-440 thousand barrels per day. West Coast at 255-275 thousand barrels per day. North Atlantic at 445-465 thousand barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $5.40 per barrel, which is higher than the second quarter, primarily due to higher energy costs. With respect to the renewable diesel segment, we 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 be $0.45 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 3.9 million gallons per day in the third quarter. Operating expenses should average $0.50 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $140 million, and total depreciation and amortization expense should be approximately $640 million. For 2022, we expect G&A expenses, excluding corporate depreciation, to be approximately $870 million. That concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. Please respect this request to ensure other callers have time to ask their questions. Thank you. Ladies and gentlemen, the floor is now open for questions. If you would like to ask a question, please press star one on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, that is star one to register a question at this time. The first question today is coming from Manav Gupta of Credit Suisse. Please go ahead. Guys, I'm gonna actually ask only one question. That is basically, can you help us understand the demand dynamics out there? There were some worries on demand destruction, then there were some worries on recessionary demand. The conversations we are having indicates that's not the case. But you have the most diversified footprint, so help us understand gasoline or diesel, what are you seeing in terms of demand out there? I'll leave it there. Thank you. Thanks, Manav. Manav, this is Gary. I can tell you know, through our wholesale channel, there's really no indication of any demand destruction. In June, we actually set sales records. We sold 911,000 barrels a day in the month of June, which surpassed our previous record in August of 2018, where we did 904,000 barrels a day. We read a lot about demand destruction, mobility data showing, you know, in that range of 3%-5% demand destruction. Again, we're not seeing in our system. We did see a bit of a lull the first couple of weeks of July, but our seven-day averages now are back to kind of that June level, with gasoline at pre-pandemic levels and diesel continuing to trend above pre-pandemic levels. Thank you, guys, and congrats on a very good quarter. Thank you. Thank you. The next question is coming from Theresa Chen of Barclays. Please go ahead. Great quarter team, very impressive. Thanks. In light of the macro developments, both on the supply side and the demand side, what are your thoughts about where the mid-cycle crack is at now structurally? Hey, Theresa, this is Lane. I'll take a crack at it, and Gary can, you know, tune me a little bit. Obviously right now it's significantly above the mid-cycle. At least our view of the mid-cycle and then probably anybody else's for that matter. With that said, you know, you gotta remember our idea of mid-cycle is we go through an entire economic cycle, like from recession to recession. That's sort of descriptive and defined, and we work through those numbers with a few adjustments. You know, I think we believe at least with the world seems to be trending in a place where the, you know, through the next economic cycle for a number of reasons, whether it's just sort of the way the energy transition's working or the lack of investment in fossil fuels. For a number of these types of reasons, we sort of see that you'll probably be above where our mid-cycle is today for the next, you know, for the next economic cycle. Yeah, I agree with what Lane said. You know, really our market outlook calls for a prolonged period where we would be above what we currently have as mid-cycle. There's a number of structural changes. You know, when you talk about high energy costs as a result of higher natural gas costs in the U.S., we have lower feedstocks costs due to our proximity to crude, natural gas. Then you're getting refiners that are now having to pay some form of a carbon tax, which raises their cost as well. As long as supply and demand balances are tight and there's a call on that capacity, it would be logical to assume it's gonna start to reset that mid-cycle level. Thank you. You know, kind of piggyback on Manav's question related to demand. If we do see a period of demand contraction or demand softness, what do you think the risk is at this point for the industry as a whole to build overwhelming amounts of inventories, given that the refining industry just lived through two and a half years of having to be extremely flexible, shutting down capacity, et cetera, to run through the pandemic? Yeah. You know, again, kind of referring back to those structural advantages we have in the U.S. on feedstock costs and energy costs and freight advantages going to South America, you know, we feel like we're in such a strong competitive position. Even if demand, you know, fell here in the United States, we would be able to export volume to and be competitive doing that, you know, in South America. This is Lane. Hey, Theresa. To your point, I mean, the extreme measures our industry took to deal with the pandemic demand destruction. It's hard to imagine outside of another pandemic demand destruction where, you know, going through a recession would have anything remotely close to that. Obviously going through the pandemic, quite a bit of capacity was taken offline. Thank you. Thank you. The next question is coming from Doug Leggate of Bank of America. Please go ahead. Good morning, everyone. Thanks for taking my questions. Guys, I guess kind of a follow-up on the mid-cycle question, but I'm gonna ask it a little differently given your unique insight into this. Pembroke is clearly an insight into what's happening in Europe. Today, I guess it's paying somewhere around $60 per thousand cubic feet of natural gas. The U.K. obviously is a little lower than that. When you think about the structural cost advantage of the U.S., which is where we are focused, I guess, on mid-cycle as opposed to global, what are the dynamics that you're seeing? Is Pembroke making money today? What's its relative competitiveness as a benchmark, let's say, for Europe versus the U.S.? Hey, Doug, it's Lane. It's a very good question, and we sort of talked about this quite a bit in terms of this advantage the United States is having with respect to, obviously, energy prices. Today, Pembroke's doing well. It did particularly well in this past quarter. You know, to give more of a precise answer around natural gas. You know, we've been mainly paying about $30 to, I don't know, maybe. This morning it was $50. But I mean, per million BTU, but I would say it's more in this 30 range. There's quite a bit of volatility. However, the U.K. is a little bit better positioned than Europe is in terms of the value that they're paying for gas. Even there's another step change, and we don't refine over there, so we're just sort of reading the same things that you guys are. There's another step change in terms of how much gas is costing in the U.K. versus some of these European refineries that are maybe not in the best situation around natural gas. You know, Pembroke's doing well. I mean, I wouldn't consider it actually to be at the marginal capacity today. Obviously, the fact that they're doing well means that we're way past them as being somebody like even them being the marginal capacity sitting out there, setting, you know, mainly the heat crack. Lane, if I may follow up real quick. Where does Pembroke sit in, to the extent you're prepared to share, on your portfolio cost curve today? Well, today it's high, right? Because of the cost of natural gas. When you look at them on the other issues, whether it's our sort of, you know, our cost per barrel or all those other, you know, sort of on an energy-adjusted basis, they're one of the most competitive refineries in Europe, and they actually look pretty good on a U.S. basis. On Solomon, I'm not gonna give exact precision, but it's a very efficient refinery. They are very, very competitive in the Atlantic Basin. Okay. Thank you. My follow-up is hopefully a quick one. You've cut your net debt in half over the past year, I guess. I, for one, as you know, I'm delighted to see some cash building on the balance sheet. I'm just curious how you think about bulletproofing your balance sheet versus stepping into perhaps share buybacks over the foreseeable future. I'll leave it there. Thanks. Thanks, Doug. This is Jason. I can take that one. You know, we'll be doing basically the same thing we've been doing in the past. Our capital allocation priorities haven't changed. We said when the margins started recovering, we'd start paying down our debt and build cash as a priority. We made really good progress on both of those fronts. As Joe and Homer mentioned on the debt side, and you mentioned, you know, we had a series of transactions start last September, running through June 1. We paid back $2.3 billion of our COVID debt so far. On the cash side, we said we plan to hold more, given what we experienced through COVID, $3-$4 billion be the range we'd look at. We're now at $5.4 billion with a net debt- to- cap of 25% at the end of the second quarter. We think we're in a good shape from those on those fronts. Now, our approach to buybacks will continue to be guided by our target payout ratio of 40%-50%, adjusted net cash from operations. We've remained at the lower end of the range so far this year, given our competing priorities of paying back the debt and building cash. We're at a 42% payout so far this year. We think we're in good shape, and we'll plan to continue doing more of the same, paying down our debt and honoring our return commitment to the shareholders. All right, guys, I appreciate the answers. Thank you. You bet, Doug. Take care. Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead. Yeah, thank you. Good morning. Good morning, Roger. Coming back to the demand thing, but maybe a little more of a forward look. You know, distillate was the big surprise kind of in the spring coming out of the winter in Europe. As we look to this next winter, I mean, if you're in Europe, it doesn't look like gas gets any cheaper. As we think about distillate or fuel oil demand there and the way we're running at this point in the summer, what do you see as the ways in which incremental diesel can make it into Europe and affect the overall Atlantic Basin margins? Yeah, it's gonna be a real challenge for us, Roger, to be able to supply a lot more diesel into Europe. If you look, you know, with the U.S. inventories where they are, the industry basically running all out. You know, we're getting back to where jet demand is recovering in the U.S., which is actually driving ULSD yields down a little bit. You know, it's very difficult for me seeing that there's gonna be a lot of flow from the U.S. into Europe. Gotcha. As a follow-up on the 40%-50% payout ratio, you know, pre-COVID, there were a number of times you ran well above that level. Now that we're in a situation where, you know, it looks like better than mid-cycle, you know, cracks are gonna persist for a while. You wanna hold more cash. Do you see this as a situation where you may undershoot or kinda consistently stay at the low end as we saw in the second quarter? Is this something that evolves as, you know, let's just say, as $4 billion of debt repayment is achieved, does it go back into that or to the high end of the range thereafter? You wanna answer the first part? Yeah. Yeah. Oh. Sure. Yeah, you're right. For the foreseeable future, at least in the next several months, we still got that competing priority of paying down our debt. I think we'll stay at the lower end while we're paying down debt. If the cycle continues to be super strong, you're right, we'll have a lot of excess cash to consider. Yeah. Roger, I agree completely with what Jason said. You know, I mean, we want to go ahead and get things cleaned up and get this balance sheet absolutely bulletproofed and carrying a bit more cash is something that makes a lot of sense to do. You'd like to have, you know, your maintenance and turnaround CapEx covered with cash on hand, the dividend covered with cash on hand, and then we'll see where we go. But anyway, I think for now we're on the right course, and as Gary has stated, it looks like the margin environment is going to be higher for some time. It certainly is today, not what we experienced in the second quarter, but certainly well above what we would consider to be a traditional mid-cycle. If we continue to build cash, we'll continue to honor the payout, and it'll probably move from the lower end to the higher end. Okay. Just maybe as one little tweak on that. As you think about dividend versus share repos, does that ultimately change once the balance sheet is back the way you want it? You know, it's been a while since you've increased the dividend, I guess, is really what I'm getting at. Should we think of that as becoming another way to return cash? Yeah, I mean, you should. That is something we'll be looking at, what we've discussed. Our short-term focus is on getting the debt back down, and we will look at that. We've said this before, we'll be measured in our approach to ensure it's something that's sustainable through the cycle, especially given what we experienced coming through COVID. That is something we'll be looking at. Great. Thank you. Mm-hmm. Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead. Hi, good morning, everyone. Good morning, Paul. It was obviously a momentous quarter for oil markets. Can you just talk a bit about what's happened in crude markets and what the outlook is in terms of obviously the Russian impacts and the various differentials we're looking at, the Brent WTI spread, everything else? Thanks. Yeah, this is Gary. I think, you know, overall, we started to see, you know, there was not certainty what would happen with the Russian sanctions. As time has gone on, it appears that, you know, the Russian oil has continued to flow, and it's a change in trade flows, not less Russian oil on the market. The combination of that, SPR barrels coming onto the market, some production growth in certain parts of the world, you know, caused flat price to come down. Then it's also caused quality differentials to be pressured somewhat. You know, in addition to the things I mentioned, you know, the early releases, the SPR, largely medium sour barrels, which pressured the differentials. We've seen high sulfur fuel oil move weaker, which high sulfur fuel oil prices tend to impact quality differentials as well. You know, some of that is, Russian resid is starting to make its way back to the market. You're seeing more high sulfur fuel oil come from Mexico, and so those things are starting to pressure the quality differentials, which we're seeing in the market today. That's very helpful. Thanks. Could you just continue that forward thought? How do you think things will change over the next six months or so? I mean, one obvious thing is that the SPR, I don't know, but I mean, presumably at some point it's got to stop being released, right? Yeah. Well, that's exactly right. I think you'll see, you know, lower volumes coming from the SPR. Most people have kind of lowered their global oil demand forecast. So I think, you know, the oil markets are fairly well-balanced. We wouldn't expect a lot of movement in the quality differentials from where they are today. Thank you. Appreciate it. Thanks, guys. Take care, Paul. Thank you. The next question is coming from John Royall of JP Morgan. Please go ahead. Hey, good morning, guys. Thanks for taking my question. So on RD, can you talk about the captures stepping down in 2Q and any moving pieces there beyond the backwardation that I know you talked about in the last quarter? And then, what do you expect the long-term captures to look like in that business once we, you know, get to a more normal-looking market structure for diesel and once you have DGD 3 up and running? Yeah, this is Erik. I think you've hit the nail on the head. Really the big difference between Q1 and Q2 was the severity of the backwardation quarter to quarter. If you look at the rest of the capture rate, which was weaker, you had soybean prices were higher and you know, obviously LCFS prices were down, sort of averaging $130 in the first quarter versus closer to $100 in the second quarter. Yeah, clearly margins tighter in the second quarter and capture rates lower, mostly due to the backwardation you mentioned. You know, if you look forward, I think, you know, you. I think, again, you've said it, that, you know, as U.S. dollar markets normalize, you'll see a little bit of a return to normal in the back half of this year for RD. Great. Just sticking with RD, I know we've had some good news on the BTC and the SAF side this morning. Could you give your latest thoughts on the LCFS program in California and where you think pricing could go there? I know we have the scoping process now to think about, and we have the federal program in Canada starting next year. Just any thoughts on pricing there into the second half and next year would be helpful. Yeah. The LCFS market in California has really seemed to have stabilized in this sort of $90-$100 range. We don't see a lot of volume moving, and as you mentioned, the scoping meetings they have, they are considering increasing the obligations, you know, into 2030, which should create a greater demand for the LCFS credits. You know, 'cause as we see now with renewable diesel and other renewables, you know, consuming up to about 50% of the obligation and gasoline demand still relatively muted on the West Coast. It's just, you know, it's the credit obligation. There's just not a big driver there. You know, I think you mentioned Canada. We see that's an opening emerging market. The world's trying to figure out what these early credit prices are gonna be valued at, as that new, you know, federal regulation in Canada goes into effect between now and next June. Then obviously with Oregon and Washington opening up, they all seem to be hanging around the same sort of $90-$100, you know, credit price. You know, obviously we wanna see. We, you know, we'd like to see that go back up, but, you know, if I was gonna, you know, have an outlook, it seems to have stabilized somewhere kind of in that range. Very helpful. Thank you. Thank you. The next question is coming from Connor Lynagh of Morgan Stanley. Please go ahead. Yeah, thanks. I wanted to return to the topic of export markets and sort of the global balance. As we get closer to Europe's proposed date to stop taking Russian refined products, what's your sort of high-level view of how the market will reposition? The sort of implication I'm wondering about here is you highlight Latin America as a key area of your exports. Is that likely to change? Do you think Russian volumes will be competitive there? Just high-level thoughts around that would be great. Yeah. It's difficult to know what's gonna happen with the sanctions. I think, you know, we see some South American countries that seem to be interested in taking some Russian barrels, so that certainly could be a scenario that develops. Some of the Russian diesel makes its way to South America, and then we backfill into Europe. I could see that happening, but we don't really have a lot of clarity what's gonna happen. I guess then I'm just trying to triangulate. Maybe this is more of a shorter-term comment, but you were suggesting earlier that there probably was not a high likelihood that U.S. diesel in particular would be flowing to Europe. Is that more of a near-term comment? If the sanctions were to be enacted, would you revisit that view or just basically what's the duration of that expectation? Yeah. Certainly in the short term, freight rates are high, and we see a better incentive going into Latin America. I don't know what's gonna happen in terms of Russian sanctions and the rebalancing, so that'll be just kind of a wait and see. All right. Fair enough. Maybe just to sneak one last one in here. Capture rates have actually held up pretty strong in the refining business. Anything that we should think about in terms of big swing factors into the third quarter here, or do you think the 2Q result is pretty indicative of where you're gonna be in the near term? Hey, Connor. It's Lane. It's, you know, it's early, but I would say nominally speaking, you know, absent any big moves in flat price, it'd be fairly similar. Appreciate it. I'll turn it back. Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead. Yeah. Good morning, team. Congrats on a great quarter here. The first question was around the Blender's Tax Credit. We got some news out of Washington last night that there could be an extension there. Just would love your perspective on what that could mean for the DGD business and how do you understand the ruminations in Washington? Well, this is Eric. I'll start. You know, the BTC obviously is, you know, part of the business model that we capture with renewable diesel, obviously. You know, we'd always said that, you know, we were fairly certain there would be some sort of a Blender's Tax Credit because there's always been one for about the last decade. We have seen that, you know, there was some view that without a Blender's Tax Credit, the D4 RIN would pick it up and, you know, maybe not perfectly dollar for dollar, but, you know, certainly in sort of the 70%-80% range. You know, we'll see how this plays out. Certainly it's supportive of the renewable business. I don't know if Rich, you wanted to comment at all on the political side? Yeah. This is Rich Walsh. I mean, we just saw the bill, you know, came out late last night, 700 pages. We're looking through it. I mean, there are some things in there that are helpful to our business. You know, the tax credit obviously we're just talking about. You know, there's also a SAF tax credit in there as well that we'll be looking at. There's other things too we're trying to sort through. You know, I think it was a surprise to everybody that came out that quick. I don't think we really ever thought that the Blender's Tax Credit was gonna be, you know, the Bio Tax Credit would be a problem. We thought it would end up on one of these bills before the end of the year. It's always good to see it, you know, looking stronger and on the forefront, so. All right. Great, guys. Follow up is just on yield switching. We're in an environment now where we're obviously heating oil and distillates trading well above gasoline. Do you see the industry and the company being able to switch to capture that? Does that take some pressure off of the distillate side of the equation and help to rebalance inventory? Yeah. Neil, this is Lane. Gary kind of addressed this a little bit. Our assets have been in max distillate mode for a few weeks, and one of the dynamics that's occurring right now is as jet recovers, it actually makes distillate yields fall, or diesel yields fall. You know, I guess that the short answer is no, Dave. I assume everybody else is, you know, doing kind of the similar thing. There's not a lot of additional diesel outside of incremental runs that somebody might have, and the industry's running at pretty high utilization rates. I don't see a big, you know, a big opportunity to make up sort of a decent shortfall right now. Thanks, Lane. Thanks, guys. Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead. Good. Thanks. Maybe a follow-up on renewable diesel and waste fat spreads and the feedstock market. Obviously we've seen those spreads narrow over in the first half of the year, and in particular, soybean oil moves pretty significantly in the recent time here. Can you talk a little bit about what you're seeing in animal fat and, you know, kind of low CI feed markets in the second half of the year? Would you expect those to widen out a little more? As you look towards the startup of DGD3, would you expect, you know, kind of a replay of what we saw late last year, where as you start buying that there's some kind of normalization and equilibrium period there where we see some volatility? I think, you know, as you said, I mean, the soybean oil market was pricey in the second quarter, but has since, you know, come down and, you know, if you look at it, you know, feedstock availability is there. I mean, we're not having any problem sourcing any of the different waste oils or animal fat feedstocks. You know, relative values, you know, it goes along with the LCFS that, you know, a lot of that is not as advantaged as it has been, you know, if you look at sort of this time last year. We certainly have availability to get the feedstocks we need for DGD3. There's no doubt with DGD3 being, you know, our third and largest unit starting up in the fourth quarter, it will change, you know, some of the trade flows, certainly in the U.S., and as well as, you know, where we can pull from, you know, all the global sources of feedstocks. I think you're right. We will see an impact to feedstocks in general, as we change a lot of the trade flows. I think it will. We'll see an equilibration sometime next year as it sort of settles out, you know, how those trade flows change. It'll be interesting. That'll be one thing we're looking at as you start up and see, you know, like I mentioned earlier, with the Canadian regulation opening up and some other markets opening up. We'll, you know, we'll be looking at, you know, how that all plays out versus feedstocks. Then maybe just a quick one on project spend and the environment. I mean, from your updates, it clearly doesn't seem to be having an impact on timing. Any impact that the inflationary environment or supply chain could have on capital budgets at things like the Port Arthur Coker Project or DGD3, as we look over the next 12 months? I know. This is Lane. All those projects were steel prices and labor and everything else was locked in prior to sort of this inflationary time that we're experiencing right now. Perfect. Thank you. Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please go ahead. Hello. How are you? Hey, Sam. Good. You? Good, thanks. I wanna ask about a comment I heard earlier on the call that made me think. You mentioned, you know, high sulfur fuel oil spreads are blowing out. We've got light sweet premiums and WCS discounts are very deep. You've also got these very wide differentials between distillate and other products, specifically gasoline. It sounds like the scenario that people imagined for IMO 2020, and I was just wondering how influential you think that is in the market today, you know, given everything else that's going on. I think you are seeing a lot of pull-through of IMO 2020 in the market today. You know, that it's contributing to the stronger distillate cracks that you're seeing because more diesel is being pulled into the marine sector, and then it's also contributing to the high sulfur fuel discounts, as well. Yeah, this is Lane. I'll add to that. It's also causing some of these really high valuations on sort of I'm gonna say, you know, sort of Atlantic Basin sweet crude because again it's a little bit. It's not unlike what's happening on natural gas. The marginal refiner trying not to make high sulfur fuel oils outbidding up the light sweet market, so they can try to stay out of that market, right? It's propping up the value of that crude versus the medium sours. Okay. Thank you. This is a follow-up sort of drilling down on the renewable diesel conversation and maybe on the policy side. You know, some feedback that we've gotten recently from other industry contacts is that renewable fuels, including ethanol, have moved very much into the energy security category and, you know, almost that's taking prominence over the carbon and emissions side. That's, you know, spurring a lot of support or incremental support, I should say, from regulators and D.C. I was wondering if you're seeing, you know, the same thing when you interact with your counterparts in the government. This is Rich. I'll take an opportunity. You know, I would just qualify by saying it, they are low carbon too, so they're not moving just into security. They're also part of the low carbon solution. You know, if you look at like our renewable diesel, it actually can outperform on a carbon intensity basis some of the EV alternatives that are out there. You know, I think what you're starting to see now is a realization among regulators that actually these low carbon liquid fuels are drop-in. They're cheaper to implement, they're available for consumers and they provide an opportunity to also solve some of the climate issues that are out there. I mean, I think what you're seeing is recognizing in the marketplace that these might be better alternatives and of course, they're domestic and a real strength of the U.S., you know, economy. It's not surprising that you're starting to see, you know, more affection for the low- carbon fuels. All right, thanks so much. Thank you. The next question is coming from Jason Gabelman of Cowen. Please go ahead. Hey. Thanks for taking my questions. I wanted to ask firstly on the policy side, and the government seemed interested in intervening in the markets when petroleum prices got too high, only a month ago, and there's obviously concerns into the back half of the year that prices can rise again, particularly on the flat crude price. I was wondering if you could maybe discuss a bit how your conversations with the government went, particularly around a petroleum product export ban or quota, and if you think that's a realistic policy option that the government could implement in the future and how that would impact you. I have a follow-up. Thanks. Okay. Lane and I had the opportunity to meet with the Secretary of Energy and members of her team in response to President Biden's request, and I would consider the meeting to be constructive. You know, she was well briefed on what the issues were and the implications of some of the policy changes that you just mentioned. We talked about various options that could be implemented in the short term that would help take some of the pressure off of fuel prices. They have those in hand, and in fact, her staff has continued to follow up with members of our team and other attendees at that meeting to see what might make sense to try to implement. It was a good meeting. Lane, anything you'd add to that? The only thing I would add is, at least I don't remember any mention of trying to limit exports. No. -not ever really- No. that was not talked about whatsoever. It goes to my point that they understand the implications of some of these decisions. You know, banning exports doesn't have the effect that they would want it to have as far as we can tell. It would probably just put some pressure on the industry, and it would certainly drive the global prices higher without the U.S. supply to backfill some of the shortfalls that are out there. They seem to have a keen grasp of that, and that was encouraging to us. No, I consider it was a constructive meeting and they're interested in solutions. You know, it's always interesting to see what happens after these conversations take place and would there be any actual follow-up with it. They're still talking. More to come, Jason. All right. Were there any potential solutions that you and the representatives you met with saw eye to eye on? Yeah. No, I think, you know, one of the things was RVP change, you know. RVP and relaxing sulfur specs. That was essentially, I think, the major, you know, I don't wanna call them policy, but essentially initiatives that you could have that would help maybe, you know, I think for some of the U.S. refiners have to export because of sulfur specs. That was fairly clear in there. I think that it was. Then the other idea was, again, like what Joe just mentioned, relaxing the RVP in some of these. You know, and what that would require is some of the non-attainment metropolitan areas would go from, you know, reformulated to a conventional blend. That's a little bigger move, but those were the things that we talked about. Got it. That's really helpful. My follow-up just on DGD, we're getting to this cash flow inflection point in the business when DGD 3 starts up. I was wondering if you could help us think about guideposts for what the cash distribution policy will be from the joint venture back to the partners or at least a time when we could expect an update on that. Thanks. Okay. Yeah. This is Jason. I'll start off, and then maybe Eric can chime in. Y'all know how DGD was. The business was built. We used cash flows from the business. It's funded all the growth or largely funded the growth till now. We will have DGD 3 coming online in fourth quarter, so there should be some excess cash flows to look out at the time, and the partners will be deciding what to do with it. Yeah. You know, obviously, we, you know, we do expect there to be a positive cash flow next year with DGD 3 starting up and capital, you know, finishing on that project. Obviously we'll have to work with our partner on, you know, what we wanna do with that cash. Like we've said, we're gonna take a pause after DGD 3 starts up and kinda take a look on the market of, you know, a lot of things we've talked about today between feedstocks and new product outlets. You know, with the recent policy discussions like, you know, that came out last night, you know, what do we wanna do with the cash? Obviously there should be a cash flow to discuss in 2023 associated with DGD. All right. Thanks. Thanks a lot for the answers. Okay. Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt & Co. Please go ahead. Hey, good morning. If this potential BTC for SAF goes through, would you think about adding SAF capability at DGD 3? If so, what kind of yields should we be thinking about? Yeah. There obviously there's a lot of things we gotta still get the details of before, but we certainly have a project in the wings that is waiting to see how this SAF credit is gonna play out. There is a project that we've looked at for, you know, that we continue to do engineering on that would bolt on SAF capability to DGD 3 with, you know, roughly a kind of a 50/50 yield of SAF and renewable diesel. It would be a significant increase in SAF capability for the U.S. Obviously the largest producer of SAF. You know, does look like it could be a possibility. Like I said, a lot of details to work through from a policy standpoint. That has to be discussed with our partner. Sounds good. Could you walk us through the Q2 hedging impacts at DGD? I think in Q1 it was a headwind of $119 million. What did that look like for Q2? Is this, like, an inventory hedge or a margin hedge? Any details there? Yeah, that's you know, those details will be in the queue. What I would say is, really, it's all just a product of backwardation being more severe in the second quarter than the first quarter. It was a larger impact, and that's why, you know, as we said earlier, margin capture was much lower, mostly just because of the market effects on ULSD. I think, you know, we see that probably looking a little more favorable in the back half of the year, but that's all gonna really be tied to how the ULSD market plays out. It currently looks better. We'll have to see how the rest of the year plays out. Great. Thank you. Thank you. That brings us to the end of the question and answer session. I would like to turn the floor back over to Mr. Bhullar for closing comments. Great. Thank you. We appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any additional questions. Thank you, everyone, and have a great day. 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