Greetings, Welcome to the CVR Energy Inc. Second Quarter 2023 conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. 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, Richard Roberts, Vice President of FP&A and IR. Thank you, Mr. Roberts. You may begin. Thank you, Camilla. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy second quarter 2023 earnings call. With me today are Dave Lamp, our Chief Executive Officer, Dane Neumann, our Chief Financial Officer, and other members of management. Prior to discussing our 2023 second quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. Actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events, or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation of the most directly comparable GAAP financial measures, are included in our 2023 second quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call. With that said, I'll turn the call over to Dave. Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported second quarter consolidated net income of $168 million and earnings per share of $1.29. EBITDA for the quarter was $300 million. Our solid results for the quarter were driven by continued strength in gasoline and diesel crack spreads. We are pleased to announce that the board of directors has authorized a special dividend of $1 per share. This is in addition to the regular second quarter dividend of $0.50 per share, both of which will be paid on August 21st to shareholders of record at the close of the market on August 14th. Our annualized dividend yield, excluding special dividends, is approximately 5.5% based on yesterday's closing price, and remains best-in-class among the independent refiners. In our petroleum segment, combined total throughput for the second quarter of 2023 was approximately 201,000 barrels per day, and light product yield was 100% on crude oil processed. We completed the planned coker turnaround at Coffeyville in early April, and we currently do not have any additional turnarounds planned for the remainder of the year. Although we experienced a fire at the gasoline hydrotreater at Wynnewood during the quarter, the impact to operations at the plant was minimal, and we were able to run the refinery without the hydrotreater in operation by consuming sulfur credits. We expect to have the hydrotreater repaired and back in service in the next week. Benchmark cracks, benchmark crack spreads remained elevated during the second quarter, with Group 3 2-1-1 averaging $32.03 per barrel. RIN prices declined slightly from the first quarter, but remained stubbornly high at over $7 per barrel. Last month, EPA continued down their ridiculous and misguided path, once again, denied petitions for Small Refinery Exemptions, including Wynnewood's petition for 2022. We've already filed lawsuits and received a stay from the Fifth Circuit related to the denial of the Wynnewood Small Refinery Exemption for 2017-2021. We expect to challenge this most recent denial in court very soon. As we have continually stated, the RFS regulation was written specifically to protect small refineries, like Wynnewood, from disproportionate economic harm caused by the RFS regulation. We will continue to fight for our rights that we believe Wynnewood is entitled to. We completed a second catalyst change at the Wynnewood Renewable Diesel unit in April, and we processed approximately 18 million gallons of vegetable oil feedstock in the second quarter. We also switched catalyst providers with the most recent change, and so far, we are seeing an increase in renewable diesel yields. The HOBO spread improved slightly from the first quarter, and despite the lower throughput volumes, we once again saw improved results relative to the previous quarter. As a reminder, our renewable diesel business is currently reported in our corporate and other segment. In the fertilizer segment, both facilities ran well during the quarter, with a consolidated ammonia utilization rate of 100%. Fertilizer prices continued to decline during the second quarter, although we sold more, sold more than 40% of our second quarter volume in the first quarter at higher prices. We recently completed both a summer fill and fall prepaid ammonia ordering from customers. We have a good order book heading into the fall. Let me turn the call over to Dane to discuss our financial highlights. Thank you, Dave, and good afternoon, everyone. For the second quarter of 2023, our consolidated net income was $168 million, earnings per share was $1.29, and EBITDA was $300 million. Our second quarter results included unfavorable inventory valuation impact of $26 million, unrealized derivative losses of $19 million, and a negative mark-to-market on our estimated outstanding RIN obligation of $2 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $347 million, and adjusted earnings per share was $1.64. Adjusted EBITDA on the petroleum segment was $258 million for the second quarter, driven by strong product cracks in the mid-con. Our second quarter realized margin, adjusted for inventory valuation, unrealized derivative losses, and RIN mark-to-market impacts, was $20.27 per barrel, representing a 63% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact, was $88 million or $4.85 per barrel, which negatively impacted our capture rate for the quarter by approximately 15%. The estimated accrued RFS obligation on the balance sheet was $599 million at June 30th, representing 373 million RINs, mark-to-market at an average price of $1.61. As a reminder, our estimated outstanding RIN obligation excludes the impact of any Small Refinery Exemptions. Direct operating expenses in the petroleum segment were $5.46 per barrel for the second quarter, compared to $6.12 per barrel in the second quarter of 2022. The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices, somewhat offset by higher repair and maintenance expenses. Adjusted EBITDA on the fertilizer segment was $87 million for the second quarter, with strong production for the quarter, somewhat offsetting the decline in nitrogen fertilizer prices relative to the second quarter of 2022. The partnership declared a distribution of $4.14 per common unit for the second quarter of 2023. As CVR Energy owns approximately 37% of CVR Partners' common units, we will receive a proportionate cash distribution of approximately $16 million. Cash provided by operations for the second quarter of 2023 was $367 million, and free cash flow was $271 million. Significant uses of cash in the quarter included $97 million of capital and turnaround spending, $70 million paid for the non-controlling interest portion of the CVR Partners' first quarter distribution, $54 million paid for cash, taxes, and interest, and $50 million paid for the CVI first quarter dividend. Total consolidated capital spending was $48 million, which included $22 million in the petroleum segment, $6 million in the fertilizer segment, $18 million on the pretreatment unit for the RDU. Turnaround spending in the second quarter was $11 million. For the full year of 2023, we estimate total consolidated capital spending to be approximately $200 million-$225 million, and turnaround spending to be approximately $55 million-$65 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $751 million, which includes $69 million of cash in the fertilizer segment. Total liquidity as of June thirtieth, excluding CVR Partners, was approximately $937 million, which was comprised primarily of $682 million of cash and availability under the ABL facility of $255 million. In light of our upcoming senior notes maturity in 2025, we are currently intending to hold higher levels of cash on the balance sheet in order to offset the potential for a growing RIN liability as we await the outcome of the lawsuits related to Wynnewood Small Refinery exemptions. Looking ahead to the third quarter of 2023, for our petroleum segment, we estimate total throughput to be approximately 200,000-215,000 barrels per day, direct operating expenses to range between $95 million and $105 million, and total capital spending to be between $45 million and $49 million. For the fertilizer segment, we estimate our third quarter 2023 ammonia utilization rate to be between 95% and 100%, direct operating expenses to be approximately $50 million-$55 million, excluding inventory impacts, and total capital spending to be between $14 million and $16 million. For renewables, we estimate third quarter 2023 total throughput to be approximately 17 million-22 million gallons, direct operating expenses to be between $6 million and $8 million, and total capital spending to be between $23 million and $25 million. With that, Dave, I'll turn the call back over to you. Thanks, Dane. In summary, we had another strong quarter with solid contributions from both the refining and fertilizer segments. We saw another quarter of improved results with the new renewable diesel business as well. As we look at the underlying fundamentals driving our business, we are optimistic about the near-term outlook, and we are pleased to be paying another special dividend to our shareholders. Starting with the refining, crack spreads remained elevated in the second quarter of 2023, with the increase in gas cracks during the quarter nearly offsetting the decline in distillate cracks. Refined product inventories remain at or below the low end of five-year ranges, demonstrating the impact of reduced refining capacity in the US and the heavy turnaround activity and unplanned unplanned outages in the first half of the year. Product inventories have also benefited from continued strong exports of gasoline and diesel out of the United States, which have averaged over 2 million barrels per day in the first half of 2023. Gasoline demand in the US has been trending above 2022 levels since March, although diesel demand has been lower for most of the year by about 5% on average. Slowing diesel demand has been one of the primary areas of concern in the market, with freight, rail, and truck movements all down this year, although freight rates have started to increase recently. The other item we continue to watch is the startup of new refining capacity around the world and the impact that may have on exports of refined products out of the U.S. On our last earnings call, I highlighted the hedging program that we entered into earlier this year, which generated a realized gain of over $11 million in the second quarter. For the second half of 2023, we have approximately 20% of our expected gasoline and diesel production volumes hedged. For 2024, we have approximately 15% hedged. On the crude side of the equation, commercial inventories have moved above the five-year average levels, which can also be partially attributed to elevated turnaround activity in the first half of 2023. Heavy crude spreads remain narrow and w e've been running very little WCS at Coffeyville as a result. Shale oil production in the United States continues to grow slowly. Our gathered volumes increased in the second quarter, averaging over 145,000 barrels per day. Crude oil exports out of the U.S. have been averaging around 4 million barrels per day, and we believe, we believe continued crude exports at this level supports a sustained Brent WTI spread. We continue to make progress on some of the refining projects we have discussed in previous calls. We have received a permit for the project to replace HF acid with a solid catalyst in the alky unit at the Wynnewood Refinery, with an expected completion in 2026. This change will increase our alkylation, alky capacity by 2,500 barrels per day as well. We are also continuing to progress our diesel yield improvement projects, which we believe could increase our distillate yield from the 2 refineries by approximately 6,000 barrels per day within 2 or 3 years. This would increase our total distillate yield from approximately 43% today to over 46%. Turning to the fertilizer segment, nitrogen fertilizer prices declined further in the second quarter, in part due to the significant decline in natural gas prices in Europe, Asia, and the U.S. We believe customer inventories are now at the lowest levels in recent years and will need to be replenished over the coming months. In July, we completed both, both the summer UAN fill and the fall prepay ammonia ordering from customers. With the reset in prices, we saw strong demand for both products and believe we have seen a recent bottom pricing in UAN and ammonia. In June, we announced that we concluded our evaluation of potential transaction to spin off our GP and LP interests in CVR Partners. The board decided not to pursue the transaction at this time. Ultimately, the board concluded the complexity associated with the transaction may not deliver appropriate value under the current conditions. We will continue to explore ways to capitalize on the unique assets of CVR Energy and CVR Partners. Finally, in renewables, construction on the PTU is progressing. However, delays in equipment delivery of equipment have shifted the expected in-service date to the fourth quarter of 2023. Over the past few months, we have had preliminary discussions with various parties that may be potentially interested in partnering on a renewable diesel project with an option for SAF production at our Coffeyville location. We are currently contemplating a significantly larger facility at Coffeyville than we have at Wynnewood as we look for ways to take as we look to explore the potential of taking advantage of the economies of scale. We would also like to be able to utilize some of the existing infrastructure at the refinery. Discussions are still in the preliminary phase at this point, but so far we have received initial interest from a variety of partners. I look forward to providing additional details as we progress these discussions. Looking at the third quarter of 2023, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $34.51 per barrel, with a Brent WTI spread of $4.32, and a Midland differential at $1.50 over WTI. Front fertilizer prices are approximately $450 per ton and UAN is $250 per ton. As of yesterday, Group 3 2-1-1 cracks were $43.08 per barrel. Brent WTI was $3.76 per barrel. WCS was $15.65 under WTI, and RINs were approximately $7.84 per barrel. We continue to strive to operate our plants in safe, reliable, and environmental responsible manner, and to explore opportunities to grow our renewables business. Continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. With that, operator, we're ready for questions. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that 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. One moment please, while we pull for questions. Thank you. Our first question is from Matthew Blair with Tudor, Pickering, Holt & Co, please proceed with your question. Hey, Dave, thanks for taking my questions, and congrats on the strong results. I want to circle back to your comments on the product crack hedges. Did I hear you correctly, that, that the realized gain was only $11 million in the quarter? We, we thought it was probably looking to be a little bit higher. And, I guess if you mark that portfolio today, do you have a sense on whether Q3 would have a similar gain or, or maybe something a little bit higher? Thank you. The $11 million is correct. That is directly from our crack hedges. We had some other hedging activities that increased that number a bit, but around crude and other products. You know, right now, if you look at the portfolio we have, we're mostly underwater in the third quarter at this point. That has a way of shifting, though. Some of the cracks we have in 2024 are still above water, but in general, the market, as you know, is really heavily backwardated, and you know, it's the front months that are really hitting us pretty hard. Okay, makes sense. Then on the potential Coffeyville RD project, appreciate that you're still in the early stages here. I guess, do you have any, any more details you can share on potential size of the project, both in terms of the capacity as well as CapEx? To clarify, would this be a, a greenfield project, or would it be, you know, a partial conversion of the refinery? Then if you could also maybe just talk about what type of partner you'd be looking for? Would this be more of like a financial partner or more of a, of a feedstock partner? Sure. Well, I think you've, you've heard us talk about the conversion of, and doing what we did at Wynnewood in the past, at, at Coffeyville. We've looked at that pretty hard, and it really doesn't pay out. The best option is to build more, I wouldn't call it greenfield, I'd call it more brownfield. It would be, in, you know, in, in proximity to the refinery. There would be some synergies with the refinery. In any case, all this, the economics are always better, when you get scale, as you get bigger. We, we were looking-- we're looking at not only, you know, upsizing it, but building what's largely practical to ship into Coffeyville itself, because that's usually limited by rail access, which is, you know, vessels no bigger than 14 feet in diameter or something like that. You know, I, I think we're looking at something much larger than what's at Wynnewood. You know, the type of partners we're really looking for, are all the above. This would be a, a fairly pricey project, should we decide to do it. The first levels of activity are really around doing the design, doing a, a full cost estimate, buying, you know, having the land to put it on, and getting the permits submitted. Until we have that, we don't really, you know, we, we're, we're pretty wide open on who partners might be. We have, as we mentioned, have had a lot of conversations with people that are interested in investing in this space. We'll look to try to monetize our position at Wynnewood with the construction of this, this joint venture, however we might structure it. Sounds good. Thank you very much. You're welcome. Thank you. Our next question is from Manav Gupta with UBS. Please proceed with your question. Good morning, guys, very strong refining results. If one didn't know that there was an outage at the gasoline hydrotreater, there's no way the results would tell you that. Help us understand, because we do know there was some kind of outage, how you managed so well around this outage, and, if it had not happened, would the results have actually even better than what we saw yesterday? Well, as you know, the, where, where the, the fire occurred was in a gasoline hydrotreater, which basically takes gasoline and treats down the sulfur to meet Tier 3 specs. We've been running that unit for quite a long time, at both Coffeyville and Wynnewood, and have generated significant credits. We monetized some of those credits during this, this time, all those credits are on our balance sheet at zero value, so you didn't see much impact in the financials. We are hurt a little bit because those are credits we could have sold, which are, right now are selling around $2,500 per credit, we could have sold those in the future. It did impact us in some ways. However, even though the fire did, did cause a disruption for a short period of time, we were pretty well able to catch that back up. I will remind you, too, that we, we finished up the coker turnaround at Coffeyville towards the beginning of the first quarter, but it did impact our rates, as we had high inventories that we had to run off. Until we, until we got those inventories back in control, we weren't at full crude rate at, at Coffeyville either. Perfect. I just have a quick follow-up. As you mentioned, you're looking at various partner options, and I understand at this point you're limited in what you can say, but would you prefer a single partner who comes in for both the refining assets, or are you actually looking for different partners for the two different assets that would potentially be RD units? Well, as you know, we restructured our company to break out renewables as a separate company, ultimately, with the idea that we could spin that if we built the scale that we think we can do. You know, I think what we're looking really at is some type of partnership with multiple parties because of the size of this, this company would be probably, you know, 600-700 million gallons a year of renewable diesel and probably half of that SAF. It's a sizable venture, and, you know, a decent market cap, so we think it has the potential to be a standalone company a nd this, this is precisely why we did the restructuring. This will allow us to to pursue this type of activity. You know, I think we want strategic, we want financial, we want all types. We'd love somebody to come in that has has the ability to help us source feed, advantage feed. We, we think Coffeyville is a really good location to build something like this because it's right in the, in the Ag Belt, and it's close proximity to a lot of ethanol plants, which, as you know, corn oil is a fairly low CI material that would allow us to capture VTC on, on any kind of SAF we might make, and enhanced VTC, I'll say, you know, it's still really early, but it's, but it's wide open, and we'll just be exploring what the, what all the alternatives are. Thank you so much for your detailed response. You're welcome. Thank you. Our next question is from John Royall with JP Morgan. Please proceed with your question. Hi, good afternoon. Thanks for taking my question. Just on the special dividend, I think I've asked on the past couple of calls, and Dave, you've talked about needing to see kind of a remarkable environment to do specials going forward, and perhaps we're in a remarkable environment right now, particularly with July gasoline cracks where they were. Is that still the bar, only paying out in very strong environments, or are you shifting policy more towards maybe something like a 100% payout type policy? You know, I think you, we've told you, you know, our, our whole drive here is to maintain attractive investment, investment profile by, by focusing on free cash flow generation and cash returns to our shareholders. That's every day in our DNA. You know, we really are targeting above average cash returns to shareholders and unitholders, and we look at repurchasing stock, units, buying down debt, all the options every quarter. We only do those when they're value added. You know, with our, with our stock price where it is today, stock buybacks don't make any sense to us. A debt buyback is, you know, we don't have anything pressing us immediately, but that'll be on our equation going forward. As far as the cracks go, I would tell you, if you look back 5 years, back to 2018, which was a pretty good year for refining, you know, the gas crack was around $14. On a RIN-adjusted basis, it was around $12. Today, we're looking at $27 on an unadjusted basis, $19 on an adjusted basis. Diesel back in 2018, on an unadjusted RIN basis, was almost $23. Today, it's $37. Adjusted on it for RINs, it's $21 and $29, almost $30. They're fairly remarkable. They're not quite as, diesel's a little less than what it was in 2022, but gasoline's very, very much stronger than what 2022 was. I would still tell you they're pretty remarkable, at least in my experience of 40 years in this business. You know, when we have the cash, we're gonna every, every quarter, the board looks at all the options and decides where to, where to put it. If we, if we don't have good investments or something that is a high return, it's gonna go back to shareholders. That's, that's exactly what we did this time. That's very helpful. Thanks, Dave. Maybe along the same lines, pro forma for the special, it looks like your cash balance is about $650 million or so. You talked about wanting to hold higher levels from here. Do you have a minimum cash balance that you're thinking of right now with that in mind? Is there any impact from the hedge program on additional cash that you have to hold there? Yeah, I'll, I'll grab this one. You know, the minimum cash balance will fluctuate just based on commodity pricing levels, heavily focused on crude price. Today, you know, we'd say our minimum cash balance is in the $400-$450 range. As we, we talk about holding a little excess cash, the, the, the primary driver there is to, to not allow our, our RIN short, particularly for Wynnewood, to grow much more. When we talk excess cash, it's really just that balance that we'd wanna cover on any growing short for the 23 position. The rest after that would become available potential cash. Thank you. You got it. Thank you. Our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question. Yeah, good morning, Dave and team. Congrats on a great quarter here. Thank you, Neil. Thanks, Dave. The first question is just, just your thoughts on the MidCon market. Obviously, we're seeing strong cracks everywhere, but MidCon sometimes can dislocate from Gulf Coast and East Coast. Just your thoughts as we go through the back half of the year, different considerations. Maybe you wanna talk about demand profile, maintenance and of course, the spreads between, Brent and WTI. Sure. Well, I think, you know, we had very, if you look at demand on the Magellan system, it's, it is basically hasn't changed much at all. Even though when I mentioned the U.S. is down a bit on diesel, you can't see it at all in the, in the MidCon. Actually, you know, we had the basis blew out a little bit into a negative point in the quarter, but that has since come back to positive numbers versus versus New York Harbor. You know, what happens then is typically the arb opens between Gulf Coast and MidCon, and barrels come up, up, up the pipelines to meet us. They've been hesitant to do that a little bit just because of the backwardation in the market. Products have been severely backwardated, and that adds a lot of risk when you have seven days of ship time. That, that's been limited. The margins have been very good in the group. You know, the premium has been even better than that. Of numbers of somewhere, I think we averaged in the second quarter, let me see, about $0.41 premium to regular. Really no trouble moving barrels, no trouble at all, making as much premium as we can. Really, it's been a, you know, it's been a very open market for any kind of production increases we could make. I'm sorry, I forgot the rest of your question. Just Brent WTI on the crude side as well, but that was great on product. Yeah, on Brent or Brent TI, you know, I think we're we've always just said that shale oil is what makes drives that number. In our area, actual shale oil production's up. Several of the E&P companies have hit pretty big sized wells and did some farming activities that they're still coming on. I, you know, you can see it in our pipeline rate. We're up to 145,000 barrels, which we were during COVID, I think we bottomed it right at 100, 105, somewhere in there. It's still happening, and with 4 million of exports that seem to be hanging in there pretty tight, a $4 Brent WTI is necessary to force that off the market, off the, off the shore. We still have that point of view that as long as shale oil production is maintaining where it is, since the Gulf Coast is mainly heavier crude refiners, that all this light crude has to go offshore. Dave, I don't want to get you animated here, but I do have to ask you every quarter about your perspectives on the, on the RINs markets and on, on RFS. Just sort of your thoughts on how, how ethanol and biodiesel RINs can evolve here, and what are, what are the next things that we as an investing community should be looking forward to as we kind of try to figure out what this means for, for, for the refining sector? Well, you know, this, this does get me fired up, Neil, as you well know. You know, I just, I just feel that the EPA has totally mismanaged this, the whole system for many, many years. They did it again with the new RVOs that came out. You know, keeping the ethanol mandate above the blend wall and actually putting pretty small numbers, frankly, for the D4 or the advanced bios. It just seems like a complete mistake to me. What are you, what are you trying to encourage here? Are you just trying to keep RIN prices high to make the consumer pay another $0.30 a gallon or what? Frankly, D6 should be cheap, D4 should be expensive. You know, if you, the BTC goes away, I think you'll see D4 even have to go a lot higher to continue to, to encourage production of renewable diesel and SAF. Yeah, it just seems to me it's, you know, they talk out of both sides of their mouth. You know, climate change is huge, and we're gonna do everything to do it, but yet we can't put an RVO out that encourages more of probably the lowest carbon liquid fuel out there. As far as the, the future, you know, I think, you know, we've, we've seen a, a big surge at our rack volumes, which helps us blend more ethanol and, and biodiesel, which it just means we have less to buy on the open market, and we're pretty much long D4 with the, with the Wynnewood situation. You know, I don't, I don't think our position's bad. If we did something like a, a big RD plant at Coffeyville, we'd be very long RINs. You know, our strategy hasn't changed. We're still investing in renewables, and minimizing what we invest other than maintain our assets and, and any value projects that improve our feedstock supply, improve our capture or our product placement in the refining side. Yeah. It's definitely less of an issue than it was before for you guys, but understood. Thank you so much. You're welcome. Thank you. Our next question is from Paul Cheng with Scotiabank. Please proceed with your question. Hi, thank you. Dave, I have to apologize first. I came in late, so you may already addressed, if it is the case. Please let me know. I will look at the transcript. Have you mentioned, or that the score, what is your RD second quarter profitability? Also that, how you think that's going to trend over the next couple quarters, if you we assume the RD margin is, the indicator is flat? Well, we haven't published any numbers on RD profitability, but we did mention that the second quarter was better than the first quarter, and the first quarter was profitable. We continue to ramp up. You know, we went through our second catalyst change. BTU comes on in the fourth quarter, and, you know, we're anticipating that'll add $0.30, $0.40, $0.50 to the per gallon to the margin. Our long-term view of soybean oil is, is, in the current market, is somewhere around the $1.50-$1.70, maybe a $1.00-$1.70 on the actual margin. That looks to be still true to us. Dave, are you currently running with all soybean oil or that you are running some, lower CI stock? We do run some corn oil, treated corn oil, but most of it is soybean oil today. We will be shifting to more corn oil as we bring the PTU on. All right. I'm just curious, I mean, a number of years ago, that you guys had, a pretty active, trying to sell the company or then looking for a merger partner. Since then, that I think that the number of companies, the management had changed in terms of your peers. Have, have you revisited whether that it's worth it, so that you can get a better economy of scale, in the refining business? Well, you know, I think, you know, we looked at all sides of the equation. Paul, as you know, we've looked at, you know, selling our assets to buying more assets in refining. We've kind of gotten to the point where I, you know, I don't think we're a consolidator, but we could be a consolidatee. You know, anything future wise, we're really focused on renewables in some form or fashion, and any other thing that could be a carbon, carbon reduction in the field. I'll tell you that it's pretty tough growing. There just aren't a lot of really great opportunities out there, even with the IRA. The problem with it is, it's, you know, it lasts 10, 12 years, and then, then what? You're left with uncompetitive assets compared to fossil fuels. It's, it's difficult to make that kind of investment when you've got that short horizon, and it takes you three to four years to build anything. Dave, you earlier, that I try, trying to make sure I heard you right. You're saying that at today's share price, buyback doesn't make sense to you. When the board and you and the management to decide whether you want to go for buyback or special dividend, and maybe then on the buyback, what kind of metrics are you guys using to determine whether that you should go for buyback or special dividend? Well, I think, it's, it's not that complicated, Paul. It's really if the share price is cheap, buybacks make a lot of sense. You know, at $35, where we're at today, we may be a little higher than that now, but, but, you know, that's, that's more difficult for us to see how that's accretive in the long haul. You know, I just, share buybacks, reduce the number of shares, but that's about all it does. Mm-hmm. Okay. A final one from me. You have excess cash, and one of your peers that, when they have excess cash, they actually get out from the inventory off-take agreement, because quite frankly, that the inventory off-take agreement basically is just a off-balance sheet financing, and they charge you a fee, and that fee is pretty high. Curious that, when you're looking at that, you guys just sign a new deal on here. Does it make sense for you then to get out from that deal or that from that kind of deals and trying to manage the inventory yourself, and then you probably will be able to save money, and yet your balance sheet is actually strong enough that to be able to do it and have excess cash? Yeah, Paul, I'll take this one. You know, we actually enjoy having the intermediation agreement in place, having just signed a new agreement. We don't find the cost to be overwhelming by any means, and they help us with a lot of credit management. There's other benefits that we enjoy outside of just having them manage our inventory. It is something we've looked at and, you know, again, we'll look at from time to time, but at this time, we're very happy about where we're headed on the intermediation front. Okay. All right, thank you. Thank you. Thank you. We have reached the end of our question and answer session. I would like to turn the floor back over to management for closing comments. I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment towards safe, reliable, and environmentally responsible operations. We look forward to reviewing our third quarter 2023 results at our next earnings call. Thank you, and have a great day. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.